Multi-Coil RFID Sensor Assembly

ABSTRACT

A communication assembly including at least one sensor assembly made up of interrogation circuitry and one or more antennae is described. The interrogation circuitry comprises at least one inductor comprising at least two sensing coils for reception of signals from the MEMS data sensors.

Natural resources such as gas, oil, and water residing in a subterraneanformation or zone are usually recovered by drilling a wellbore into thesubterranean formation while circulating a drilling fluid in thewellbore. After terminating the circulation of the drilling fluid, astring of pipe (e.g., casing) is run in the wellbore. The drilling fluidis then usually circulated downward through the interior of the pipe andupward through the annulus, which is located between the exterior of thepipe and the walls of the wellbore. Next, primary cementing is typicallyperformed whereby a cement slurry is placed in the annulus and permittedto set into a hard mass (i.e., sheath) to thereby attach the string ofpipe to the walls of the wellbore and seal the annulus. Subsequentsecondary cementing operations may also be performed. One example of asecondary cementing operation is squeeze cementing whereby a cementslurry is employed to plug and seal off undesirable flow passages in thecement sheath and/or the casing. Non-cementitious sealants are alsoutilized in preparing a wellbore. For example, polymer, resin, orlatex-based sealants may be desirable for placement behind casing.

To enhance the life of the well and minimize costs, sealant slurries arechosen based on calculated stresses and characteristics of the formationto be serviced. Suitable sealants are selected based on the conditionsthat are expected to be encountered during the sealant service life.Once a sealant is chosen, it is desirable to monitor and/or evaluate thehealth of the sealant so that timely maintenance can be performed andthe service life maximized. The integrity of sealant can be adverselyaffected by conditions in the well. For example, cracks in cement mayallow water influx while acid conditions may degrade cement. The initialstrength and the service life of cement can be significantly affected byits moisture content from the time that it is placed. Moisture andtemperature are the primary drivers for the hydration of many cementsand are critical factors in the most prevalent deteriorative processes,including damage due to freezing and thawing, alkali-aggregate reaction,sulfate attack and delayed Ettringite (hexacalcium aluminate trisulfate)formation. Thus, it can be desirable to measure one or more sealantparameters (e.g., moisture content, temperature, pH and ionconcentration) in order to monitor sealant integrity.

Active, embeddable sensors can involve drawbacks that make themundesirable for use in a well bore environment. For example, low-powered(e.g., nanowatt) electronic moisture sensors are available, but haveinherent limitations when embedded within cement. The highly alkalienvironment can damage their electronics, and they are sensitive toelectromagnetic noise. Additionally, power must be provided from aninternal battery to activate the sensor and transmit data, whichincreases sensor size and decreases useful life of the sensor.Accordingly, an ongoing need exists for improved methods of monitoringwellbore sealant condition from placement through the service lifetimeof the sealant.

Likewise, in performing wellbore servicing operations, an ongoing needexists for improvements related to monitoring and/or detecting acondition and/or location of a wellbore, formation, wellbore servicingtool, wellbore servicing fluid, or combinations thereof. Additionally,the usefulness of such monitoring is greatly improved throughmeasurements in azimuthally defined regions of the annulus.

Such needs may be met by the systems and methods for use of RFID tags,in some cases with MEMS sensors, down hole in accordance with thevarious embodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a flow chart illustrating a method in accordance with someembodiments.

FIG. 2 is a schematic of a typical onshore oil or gas drilling rig andwellbore in accordance with some embodiments.

FIG. 3 is a flow chart illustrating a method for determining when areverse cementing operation is complete and for subsequent optionalactivation of a downhole tool in accordance with some embodiments.

FIG. 4 is a flow chart illustrating a method for selecting between agroup of sealant compositions in accordance with some embodiments.

FIG. 5 is a schematic view of an embodiment of a wellbore parametersensing system.

FIG. 6 is a schematic view of another embodiment of a wellbore parametersensing system.

FIG. 7 is a schematic view of still another embodiment of a wellboreparameter sensing system.

FIG. 8 is a flow chart illustrating a method for servicing a wellbore inaccordance with some embodiments.

FIG. 9 is a schematic view of a further embodiment of a wellboreparameter sensing system.

FIG. 10 is a schematic view of yet another embodiment of a wellboreparameter sensing system.

FIG. 11 is a cross-sectional view of a communication assembly inaccordance with some embodiments.

FIG. 12A is a schematic view of a single lobe sensor according to someembodiments.

FIG. 12B is a schematic view of a multi-lobe sensor according to someembodiments.

FIG. 13A is a circuit diagram according to some embodiments.

FIG. 13B is a circuit diagram according to other embodiments.

FIG. 14 is a side view of a communication assembly in accordance with afirst embodiment.

FIG. 15 is a side view of a communication assembly in accordance with asecond embodiment.

FIG. 16A is a side view of a communication assembly in accordance with athird embodiment.

FIG. 16B is a side view of a communication assembly in accordance with afourth embodiment.

FIG. 17 is one embodiment of an interrogation tool in accordance withthe present disclosure.

DESCRIPTION

The following discussion is directed to various embodiments of theinvention. The drawing figures are not necessarily to scale. Certainfeatures of the embodiments may be shown exaggerated in scale or insomewhat schematic form and some details of conventional elements maynot be shown in the interest of clarity and conciseness. Although one ormore of these embodiments may be preferred, the embodiments disclosedshould not be interpreted, or otherwise used, as limiting the scope ofthe disclosure, including the claims. It is to be fully recognized thatthe different teachings of the embodiments discussed below may beemployed separately or in any suitable combination to produce desiredresults. In addition, one skilled in the art will understand that thefollowing description has broad application, and the discussion of anyembodiment is meant only to be exemplary of that embodiment, and notintended to intimate that the scope of the disclosure, including theclaims, is limited to that embodiment.

Certain terms are used throughout the following description and claimsto refer to particular features or components. As one skilled in the artwill appreciate, different persons may refer to the same feature orcomponent by different names. This document does not intend todistinguish between components or features that differ in name but notfunction, unless specifically stated. In the following discussion and inthe claims, the terms “including” and “comprising” are used in anopen-ended fashion, and thus should be interpreted to mean “including,but not limited to . . . .” Also, the term “couple” or “couples” isintended to mean either an indirect or direct connection. In addition,the terms “axial” and “axially” generally mean along or parallel to acentral axis (e.g., central axis of a body or a port), while the terms“radial” and “radially” generally mean perpendicular to the centralaxis. The use of “top,” “bottom,” “above,” “below,” and variations ofthese terms is made for convenience, but does not require any particularorientation of the components.

Communication assemblies are deployed in a borehole for a well, such asan oil well or other hydrocarbon recovery well. The communicationassemblies are coupled to a casing string (e.g., the exterior of thecasing), and may detect RFID tags or other properties of material (e.g.,fluids) in an annulus surrounding the casing string. A communicationassembly may include one or more RFID sensor assembly(s) each having atleast one multi-coil sensor improving the detection quality of RFID tagsin one or more azimuthally oriented or longitudinally oriented regionsof the annulus surrounding the casing.

This disclosure relates to the field of drilling, completing, servicing,and treating a subterranean well, such as a hydrocarbon recovery well.In particular, the present disclosure relates to systems and methods fordetecting and/or monitoring the position and/or condition of wellborecompositions, for example wellbore sealants such as cement, using RFIDtags (in some cases including micro-electrical mechanical system(MEMS)-based data sensors). In some embodiments, the present disclosuredescribes an interrogation circuit that includes multiple coils toimprove or expand the azimuthal or longitudinal coverage of the sensorassembly and a method for using the multi-coil sensor circuit to monitorRFID tags and embeddable data sensors capable of detecting parameters ina wellbore composition. The multitude of coils may be drivenindividually or may be driven with a single circuit.

Disclosed herein are methods and products for detecting and/ormonitoring the position and/or condition of a wellbore, a formation, awellbore service tool, and/or wellbore compositions, for examplewellbore sealants such as cement, using MEMS-based data sensors. Stillmore particularly, the present disclosure describes methods ofmonitoring the integrity and performance of wellbore compositions overthe life of the well using MEMS-based data sensors. Performance may beindicated by changes, for example, in various parameters, including, butnot limited to, moisture content, temperature, pH, and various ionconcentrations (e.g., sodium, chloride, and potassium ions) of thecement. In embodiments, the methods comprise the use of embeddable datasensors capable of detecting parameters in a wellbore composition, forexample a sealant such as cement. In embodiments, the methods providefor evaluation of sealant during mixing, placement, and/or curing of thesealant within the wellbore. In another embodiment, the method is usedfor sealant evaluation from placement and curing throughout its usefulservice life, and where applicable to a period of deterioration andrepair. In embodiments, the methods of this disclosure may be used toprolong the service life of the sealant, lower costs, and enhancecreation of improved methods of remediation. Additionally, methods aredisclosed for determining the location of sealant within a wellbore,such as for determining the location of a cement slurry during primarycementing of a wellbore as discussed further herein. Additionalembodiments and methods for employing MEMS-based data sensors in awellbore are described herein.

The methods and products disclosed herein comprise the use of variouswellbore compositions, including sealants and other wellbore servicingfluids. As used herein, “wellbore composition” includes any compositionthat may be prepared or otherwise provided at the surface and placeddown the wellbore, typically by pumping. As used herein, a “sealant”refers to a fluid used to secure components within a wellbore or to plugor seal a void space within the wellbore. Sealants, and in particularcement slurries and non-cementitious compositions, are used as wellborecompositions in several embodiments described herein, and it is to beunderstood that the methods and products described herein are applicablefor use with other wellbore compositions. As used herein, “servicingfluid” refers to a fluid used to drill, complete, work over, fracture,repair, treat, or in any way prepare or service a wellbore for therecovery of materials residing in a subterranean formation penetrated bythe wellbore. Examples of servicing fluids include, but are not limitedto, cement slurries, non-cementitious sealants, drilling fluids or muds,spacer fluids, fracturing fluids or completion fluids, all of which arewell known in the art. While fluid is generally understood to encompassmaterial in a pumpable state, reference to a wellbore servicing fluidthat is settable or curable (e.g., a sealant such as cement) includes,unless otherwise noted, the fluid in a pumpable and/or set state, aswould be understood in the context of a given wellbore servicingoperation. Generally, wellbore servicing fluid and wellbore compositionmay be used interchangeably unless otherwise noted. The servicing fluidis for use in a wellbore that penetrates a subterranean formation. It isto be understood that “subterranean formation” encompasses both areasbelow exposed earth and areas below earth covered by water such as oceanor fresh water. The wellbore may be a substantially vertical wellboreand/or may contain one or more lateral wellbores, for example asproduced via directional drilling. As used herein, components arereferred to as being “integrated” if they are formed on a common supportstructure placed in packaging of relatively small size, or otherwiseassembled in close proximity to one another.

Discussion of an embodiment of the method of the present disclosure willnow be made with reference to the flowchart of FIG. 1, which includesmethods of placing MEMS sensors in a wellbore and gathering data. Atblock 100, data sensors are selected based on the parameter(s) or otherconditions to be determined or sensed within the wellbore. At block 102,a quantity of data sensors is mixed with a wellbore composition, forexample a sealant slurry. In embodiments, data sensors are added to asealant by any methods known to those of skill in the art. For example,the sensors may be mixed with a dry material, mixed with one more liquidcomponents (e.g., water or a non-aqueous fluid), or combinationsthereof. The mixing may occur onsite, for example addition of thesensors into a bulk mixer such as a cement slurry mixer. The sensors maybe added directly to the mixer, may be added to one or more componentstreams and subsequently fed to the mixer, may be added downstream ofthe mixer, or combinations thereof. In embodiments, data sensors areadded after a blending unit and slurry pump, for example, through alateral by-pass. The sensors may be metered in and mixed at the wellsite, or may be pre-mixed into the composition (or one or morecomponents thereof) and subsequently transported to the well site. Forexample, the sensors may be dry mixed with dry cement and transported tothe well site where a cement slurry is formed comprising the sensors.Alternatively or additionally, the sensors may be pre-mixed with one ormore liquid components (e.g., mix water) and transported to the wellsite where a cement slurry is formed comprising the sensors. Theproperties of the wellbore composition or components thereof may be suchthat the sensors distributed or dispersed therein do not substantiallysettle during transport or placement.

The wellbore composition, e.g., sealant slurry, is then pumped downholeat block 104, whereby the sensors are positioned within the wellbore.For example, the sensors may extend along all or a portion of the lengthof the wellbore adjacent the casing. The sealant slurry may be placeddownhole as part of a primary cementing, secondary cementing, or othersealant operation as described in more detail herein. At block 106, adata interrogation tool (also referred to as a data interrogator tool,data interrogator, interrogator, interrogation/communication tool orunit, or the like) is positioned in an operable location to gather datafrom the sensors, for example lowered or otherwise placed within thewellbore proximate the sensors. In various embodiments, one or more datainterrogators may be placed downhole (e.g., in a wellbore) prior to,concurrent with, and/or subsequent to placement in the wellbore of awellbore composition comprising MEMS sensors. At block 108, the datainterrogation tool interrogates the data sensors (e.g., by sending outan RF signal) while the data interrogation tool traverses all or aportion of the wellbore containing the sensors. The data sensors areactivated to record and/or transmit data at block 110 via the signalfrom the data interrogation tool. At block 112, the data interrogationtool communicates the data to one or more computer components (e.g.,memory and/or microprocessor) that may be located within the tool, atthe surface, or both. The data may be used locally or remotely from thetool to calculate the location of each data sensor and correlate themeasured parameter(s) to such locations to evaluate sealant performance.The data interrogation tool can comprise MEMS sensor interrogationfunctionality, communication functionality (e.g., transceiverfunctionality), or both. The data interrogation tool which will bedescribed herein includes at least one communication assembly whichcommunication assembly includes at least one sensor assembly includinginterrogation circuitry and one or more antennae. The sensor assemblycomprises a multi-coil sensor assembly comprising at least two sensorcoils. The use of multiple sensor coils allows one to configure thelocation and shape of the coils and correspondingly to shape the fieldpattern that is created. According to one embodiment, the sensor coilcan be part of a tuned RF circuit when at least one capacitor isprovided in addition to the inductance provided by the coil. Accordingto one embodiment, the sensor takes the form of a bandpass filter, forexample, if three sensor coils are included, the tuned circuit could bea seventh order bandpass filter.

Data gathering, as shown in blocks 106 to 112 of FIG. 1, may be carriedout at the time of initial placement in the well of the wellborecomposition comprising MEMS sensors, for example during drilling (e.g.,drilling fluid comprising MEMS sensors) or during cementing (e.g.,cement slurry comprising MEMS sensors) as described in more detailbelow. Additionally or alternatively, data gathering may be carried outat one or more times subsequent to the initial placement in the well ofthe wellbore composition comprising MEMS sensors. For example, datagathering may be carried out at the time of initial placement in thewell of the wellbore composition comprising MEMS sensors or shortlythereafter to provide a baseline data set. As the well is operated forrecovery of natural resources over a period of time, data gathering maybe performed additional times, for example at regular maintenanceintervals such as every 1 year, 5 years, or 10 years. The data recoveredduring subsequent monitoring intervals can be compared to the baselinedata as well as any other data obtained from previous monitoringintervals, and such comparisons may indicate the overall condition ofthe wellbore. For example, changes in one or more sensed parameters mayindicate one or more problems in the wellbore. Alternatively,consistency or uniformity in sensed parameters may indicate nosubstantive problems in the wellbore. The data may comprise anycombination of parameters sensed by the MEMS sensors as present in thewellbore, including but not limited to temperature, pressure, ionconcentration, stress, strain, gas concentration, etc. In an embodiment,data regarding performance of a sealant composition includes cementslurry properties such as density, rate of strength development,thickening time, fluid loss, and hydration properties; plasticityparameters; compressive strength; shrinkage and expansioncharacteristics; mechanical properties such as Young's Modulus andPoisson's ratio; tensile strength; resistance to ambient conditionsdownhole such as temperature and chemicals present; or any combinationthereof, and such data may be evaluated to determine long termperformance of the sealant composition (e.g., detect an occurrence ofradial cracks, shear failure, and/or de-bonding within the set sealantcomposition) in accordance with embodiments set forth in K. Ravi and H.Xenakis, “Cementing Process Optimized to Achieve Zonal Isolation,”presented at PETROTECH-2007 Conference, New Delhi, India. In anembodiment, data (e.g., sealant parameters) from a plurality ofmonitoring intervals is plotted over a period of time, and a resultantgraph is provided showing an operating or trend line for the sensedparameters. Atypical changes in the graph as indicated for example by asharp change in slope or a step change on the graph may provide anindication of one or more present problems or the potential for a futureproblem. Accordingly, remedial and/or preventive treatments or servicesmay be applied to the wellbore to address present or potential problems.

In embodiments, the MEMS sensors are contained within a sealantcomposition placed substantially within the annular space between acasing and the wellbore wall. That is, substantially all of the MEMSsensors are located within or in close proximity to the annular space.In an embodiment, the wellbore servicing fluid comprising the MEMSsensors (and thus likewise the MEMS sensors) does not substantiallypenetrate, migrate, or travel into the formation from the wellbore. Inan alternative embodiment, substantially all of the MEMS sensors arelocated within, adjacent to, or in close proximity to the wellbore, forexample less than or equal to about 1 foot, 3 feet, 5 feet, or 10 feetfrom the wellbore. Such adjacent or close proximity positioning of theMEMS sensors with respect to the wellbore is in contrast to placing MEMSsensors in a fluid that is pumped into the formation in large volumesand substantially penetrates, migrates, or travels into or through theformation, for example as occurs with a fracturing fluid or a floodingfluid. Thus, in embodiments, the MEMS sensors are placed proximate oradjacent to the wellbore (in contrast to the formation at large), andprovide information relevant to the wellbore itself and compositions(e.g., sealants) used therein (again in contrast to the formation or aproducing zone at large). In alternative embodiments, the MEMS sensorsare distributed from the wellbore into the surrounding formation (e.g.,additionally or alternatively non-proximate or non-adjacent to thewellbore), for example as a component of a fracturing fluid or aflooding fluid described in more detail herein.

In embodiments, the sealant is any wellbore sealant known in the art.Examples of sealants include cementitious and non-cementitious sealantsboth of which are well known in the art. In embodiments,non-cementitious sealants comprise resin based systems, latex basedsystems, or combinations thereof. In embodiments, the sealant comprisesa cement slurry with styrene-butadiene latex (e.g., as disclosed in U.S.Pat. No. 5,588,488 incorporated by reference herein in its entirety).Sealants may be utilized in setting expandable casing, which is furtherdescribed below. In other embodiments, the sealant is a cement utilizedfor primary or secondary wellbore cementing operations, as discussedfurther below.

In embodiments, the sealant is cementitious and comprises a hydrauliccement that sets and hardens by reaction with water. Examples ofhydraulic cements include but are not limited to Portland cements (e.g.,classes A, B, C, G, and H Portland cements), pozzolana cements, gypsumcements, phosphate cements, high alumina content cements, silicacements, high alkalinity cements, shale cements, acid/base cements,magnesia cements, fly ash cement, zeolite cement systems, cement kilndust cement systems, slag cements, micro-fine cement, metakaolin, andcombinations thereof. Examples of sealants are disclosed in U.S. Pat.Nos. 6,457,524; 7,077,203; and 7,174,962, each of which is incorporatedherein by reference in its entirety. In an embodiment, the sealantcomprises a sorel cement composition, which typically comprisesmagnesium oxide and a chloride or phosphate salt which together form forexample magnesium oxychloride. Examples of magnesium oxychloridesealants are disclosed in U.S. Pat. Nos. 6,664,215 and 7,044,222, eachof which is incorporated herein by reference in its entirety.

The wellbore composition (e.g., sealant) may include a sufficient amountof water to form a pumpable slurry. The water may be fresh water or saltwater (e.g., an unsaturated aqueous salt solution or a saturated aqueoussalt solution such as brine or seawater). In embodiments, the cementslurry may be a lightweight cement slurry containing foam (e.g., foamedcement) and/or hollow beads/microspheres. In an embodiment, the MEMSsensors are incorporated into or attached to all or a portion of thehollow microspheres. Thus, the MEMS sensors may be dispersed within thecement along with the microspheres. Examples of sealants containingmicrospheres are disclosed in U.S. Pat. Nos. 4,234,344; 6,457,524; and7,174,962, each of which is incorporated herein by reference in itsentirety. In an embodiment, the MEMS sensors are incorporated into afoamed cement such as those described in more detail in U.S. Pat. Nos.6,063,738; 6,367,550; 6,547,871; and 7,174,962, each of which isincorporated by reference herein in its entirety.

In some embodiments, additives may be included in the cement compositionfor improving or changing the properties thereof. Examples of suchadditives include but are not limited to accelerators, set retarders,defoamers, fluid loss agents, weighting materials, dispersants,density-reducing agents, formation conditioning agents, lost circulationmaterials, thixotropic agents, suspension aids, or combinations thereof.Other mechanical property modifying additives, for example, fibers,polymers, resins, latexes, and the like can be added to further modifythe mechanical properties. These additives may be included singularly orin combination. Methods for introducing these additives and theireffective amounts are known to one of ordinary skill in the art.

In embodiments, the MEMS sensors are contained within a wellborecomposition that forms a filtercake on the face of the formation whenplaced downhole. For example, various types of drilling fluids, alsoknown as muds or drill-in fluids have been used in well drilling, suchas water-based fluids, oil-based fluids (e.g., mineral oil,hydrocarbons, synthetic oils, esters, etc.), gaseous fluids, or acombination thereof. Drilling fluids typically contain suspended solids.Drilling fluids may form a thin, slick filter cake on the formation facethat provides for successful drilling of the wellbore and helps preventloss of fluid to the subterranean formation. In an embodiment, at leasta portion of the MEMS remain associated with the filtercake (e.g.,disposed therein) and may provide information as to a condition (e.g.,thickness) and/or location of the filtercake. Additionally or in thealternative at least a portion of the MEMS remain associated withdrilling fluid and may provide information as to a condition and/orlocation of the drilling fluid.

In embodiments, the MEMS sensors are contained within a wellborecomposition that when placed downhole under suitable conditions toinduce fractures within the subterranean formation.Hydrocarbon-producing wells often are stimulated by hydraulic fracturingoperations, wherein a fracturing fluid may be introduced into a portionof a subterranean formation penetrated by a wellbore at a hydraulicpressure sufficient to create, enhance, and/or extend at least onefracture therein. Stimulating or treating the wellbore in such waysincreases hydrocarbon production from the well. In some embodiments, theMEMS sensors may be contained within a wellbore composition that whenplaced downhole enters and/or resides within one or more fractureswithin the subterranean formation. In such embodiments, the MEMS sensorsprovide information as to the location and/or condition of the fluidand/or fracture during and/or after treatment. In an embodiment, atleast a portion of the MEMS remain associated with a fracturing fluidand may provide information as to the condition and/or location of thefluid. Fracturing fluids often contain proppants that are depositedwithin the formation upon placement of the fracturing fluid therein, andin an embodiment a fracturing fluid contains one or more proppants andone or more MEMS. In an embodiment, at least a portion of the MEMSremain associated with the proppants deposited within the formation(e.g., a proppant bed) and may provide information as to the condition(e.g., thickness, density, settling, stratification, integrity, etc.)and/or location of the proppants. Additionally or in the alternative atleast a portion of the MEMS remain associated with a fracture (e.g.,adhere to and/or retained by a surface of a fracture) and may provideinformation as to the condition (e.g., length, volume, etc.) and/orlocation of the fracture. For example, the MEMS sensors may provideinformation useful for ascertaining the fracture complexity.

In embodiments, the MEMS sensors are contained in a wellbore composition(e.g., gravel pack fluid) which is employed in a gravel packingtreatment, and the MEMS may provide information as to the conditionand/or location of the wellbore composition during and/or after thegravel packing treatment. Gravel packing treatments are used, interalia, to reduce the migration of unconsolidated formation particulatesinto the wellbore. In gravel packing operations, particulates, referredto as gravel, are carried to a wellbore in a subterranean producing zoneby a servicing fluid known as carrier fluid. That is, the particulatesare suspended in a carrier fluid, which may be viscosified, and thecarrier fluid is pumped into a wellbore in which the gravel pack is tobe placed. As the particulates are placed in the zone, the carrier fluidleaks off into the subterranean zone and/or is returned to the surface.The resultant gravel pack acts as a filter to separate formation solidsfrom produced fluids while permitting the produced fluids to flow intoand through the wellbore. When installing the gravel pack, the gravel iscarried to the formation in the form of a slurry by mixing the gravelwith a viscosified carrier fluid. Such gravel packs may be used tostabilize a formation while causing minimal impairment to wellproductivity. The gravel, inter alia, acts to prevent the particulatesfrom occluding the screen or migrating with the produced fluids, and thescreen, inter alia, acts to prevent the gravel from entering thewellbore. In an embodiment, the wellbore servicing composition (e.g.,gravel pack fluid) comprises a carrier fluid, gravel and one or moreMEMS. In an embodiment, at least a portion of the MEMS remain associatedwith the gravel deposited within the wellbore and/or formation (e.g., agravel pack/bed) and may provide information as to the condition (e.g.,thickness, density, settling, stratification, integrity, etc.) and/orlocation of the gravel pack/bed.

In various embodiments, the MEMS may provide information as to alocation, flow path/profile, volume, density, temperature, pressure, ora combination thereof of a sealant composition, a drilling fluid, afracturing fluid, a gravel pack fluid, or other wellbore servicing fluidin real time such that the effectiveness of such service may bemonitored and/or adjusted during performance of the service to improvethe result of same. Accordingly, the MEMS may aid in the initialperformance of the wellbore service additionally or alternatively toproviding a means for monitoring a wellbore condition or performance ofthe service over a period of time (e.g., over a servicing intervaland/or over the life of the well). For example, the one or more MEMSsensors may be used in monitoring a gas or a liquid produced from thesubterranean formation. MEMS present in the wellbore and/or formationmay be used to provide information as to the condition (e.g.,temperature, pressure, flow rate, composition, etc.) and/or location ofa gas or liquid produced from the subterranean formation. In anembodiment, the MEMS provide information regarding the composition of aproduced gas or liquid. For example, the MEMS may be used to monitor anamount of water produced in a hydrocarbon producing well (e.g., amountof water present in hydrocarbon gas or liquid), an amount of undesirablecomponents or contaminants in a produced gas or liquid (e.g., sulfur,carbon dioxide, hydrogen sulfide, etc. present in hydrocarbon gas orliquid), or a combination thereof.

In embodiments, the data sensors added to the wellbore composition,e.g., sealant slurry, etc., are passive sensors that do not requirecontinuous power from a battery or an external source in order totransmit real-time data. In embodiments, the data sensors aremicro-electromechanical systems (MEMS) comprising one or more (andtypically a plurality of) MEMS devices, referred to herein as MEMSsensors. MEMS devices are well known and any suitable MEMS devices canbe used with the described sensing assembly. According to oneembodiment, MEMS sensors can be a semiconductor device with mechanicalfeatures on the micrometer scale. According to this embodiment MEMS canintegrate mechanical elements, sensors, actuators, and electronics on acommon substrate. Such MEMS sensors include mechanical elements whichare movable by an input energy (electrical energy or other type ofenergy). In embodiments, the substrate may comprise silicon.

According to one embodiment, MEMS sensors can include a combination ofactive and passive elements. According to yet another embodiment, MEMSsensors can be configured with only passive elements. According to thisembodiment, a passive RFID MEMS sensor can be fabricated, for example,on a quartz, fused silica or other art recognized substrate.

Using MEMS, a sensor assembly may be designed based on a number ofphysical phenomena, including thermal, biological, optical, chemical,and magnetic effects or stimulation. MEMS devices are generally minutein size, have low power requirements, if any, are relatively inexpensiveand are rugged, and thus are well suited for use in wellbore servicingoperations.

According to one embodiment, the MEMS sensors added to a wellboreservicing fluid may be active sensors, for example powered by aninternal battery that is rechargeable or otherwise powered and/orrecharged by other downhole power sources such as heat capture/transferand/or fluid flow, as described in more detail herein.

In embodiments, the data sensors comprise an active material connectedto (e.g., mounted within or mounted on the surface of) an enclosure, theactive material being liable to respond to a wellbore parameter, and theactive material being operably connected to (e.g., in physical contactwith, surrounding, or coating) a capacitive MEMS element. In variousembodiments, the MEMS sensors sense one or more parameters within thewellbore. In an embodiment, the parameter is temperature. Alternatively,the parameter is pH. Alternatively, the parameter is moisture content.Still alternatively, the parameter may be ion concentration (e.g.,chloride, sodium, and/or potassium ions). The MEMS sensors may alsosense well cement characteristic data such as stress, strain, orcombinations thereof. In embodiments, the MEMS sensors of the presentdisclosure may comprise active materials that respond to two or moremeasurements. In such a way, two or more parameters may be monitored.

In addition or in the alternative, a MEMS sensor incorporated within oneor more of the wellbore compositions disclosed herein may provideinformation that allows a condition (e.g., thickness, density, volume,settling, stratification, etc.) and/or location of the compositionwithin the subterranean formation to be detected.

Suitable active materials, such as dielectric materials, that respond ina predictable and stable manner to changes in parameters over a longperiod may be identified according to methods well known in the art, forexample see, e.g., Ong, Zeng and Grimes. “A Wireless, Passive CarbonNanotube-based Gas Sensor,” IEEE Sensors Journal, 2, 2, (2002) 82-88;Ong, Grimes, Robbins and Singl, “Design and application of a wireless,passive, resonant-circuit environmental monitoring sensor,” Sensors andActuators A, 93 (2001) 33-43, each of which is incorporated by referenceherein in its entirety. MEMS sensors suitable for the methods of thepresent disclosure that respond to various wellbore parameters aredisclosed in U.S. Pat. No. 7,038,470 B1 that is incorporated herein byreference in its entirety.

According to one embodiment, the MEMS sensors are coupled with radiofrequency identification devices (RFIDs) and can thus detect andtransmit parameters and/or well cement characteristic data formonitoring the cement during its service life. According to thisembodiment RFIDs combine a microchip with an antenna (the RFID chip andthe antenna are collectively referred to as the “transponder” or the“tag”). The antenna provides the RFID chip with power when exposed to anarrow band, high frequency electromagnetic field from a transceiver. Adipole antenna or a coil, depending on the operating frequency,connected to the RFID chip, powers the transponder when current isinduced in the antenna by an RF signal from the transceiver's antenna.Such a device can return a unique identification “ID” number bymodulating and re-radiating the radio frequency (RF) wave.

Passive RF tags are gaining widespread use due to their low cost,indefinite life, simplicity, efficiency, ability to identify parts at adistance without contact (tether-free information transmission ability).These robust and tiny tags are attractive from an environmentalstandpoint as they require no battery. The MEMS sensor and RFID tag arepreferably integrated into a single component (e.g., chip or substrate),or may alternatively be separate components operably coupled to eachother. According to one embodiment, an integrated, passive MEMS/RFIDsensor contains a data sensing component, an optional memory, and anRFID antenna, whereby excitation energy is received and powers up thesensor, thereby sensing a present condition and/or accessing one or morestored sensed conditions from memory and transmitting same via the RFIDantenna.

According to another embodiment, the MEMS itself may be an RFID device.According to this embodiment, the MEMS is configured as a would be anelectronic article surveillance (EAS) device. An EAS device is mostcommonly recognized for its use in store merchandise surveillance. Sucha MEMS may be configured as an LC circuit or a 1-bit RFID. According tothis embodiment, the MEMS comprises an inductor and a capacitor thattogether create an electrical resonator. Sensing is generally achievedby sweeping around the resonant frequency and detecting the dip.

In embodiments, MEMS sensors respond to different frequencies. Accordingto one embodiment, MEMS sensors have different RFID tags, i.e., antennasthat respond to RF waves of different frequencies and power the RFIDchip In response to exposure to RF waves of different frequencies may beadded to different wellbore compositions. Within the United States,commonly used operating bands for RFID systems center on 125 kHz, 13.56MHz or 2.45 GHz. Frequencies may be limited in the event they are closeenough to the surface to be subject to surface frequencies. Dependingupon the frequency and the type of MEMS used, the range of the RFID chipcan change. When a 2.45 GHz carrier frequency is used, the range of anactive RFID chip can be many meters. While this is useful for remotesensing, there may be multiple transponders within the RF field. Inorder to prevent these devices from interacting and garbling the data,anti-collision schemes are used, as are known in the art. Inembodiments, the data sensors are integrated with local trackinghardware to transmit their position as they flow within a wellborecomposition such as a sealant slurry.

According to one embodiment, the sensing assembly as described is notsubject to interference from the surface of the wellbore. Accordingly,the frequency can be chosen based upon convenience or a number ofcriteria, including but not limited to, size of the wellbore, the typeof MEMS used, and the distance between the MEMS and the sensingassembly. According to one embodiment, the frequency is in the 300 to750 MHz range, for example in the 350 to 700 MHz, for example in the 380to 650 MHz.

The data sensors may form a network using wireless links to neighboringdata sensors and have location and positioning capability through, forexample, local positioning algorithms as are known in the art. Thesensors may organize themselves into a network by listening to oneanother, therefore allowing communication of signals from the farthestsensors towards the sensors closest to the interrogator to allowuninterrupted transmission and capture of data. In such embodiments, theinterrogator tool may not need to traverse the entire section of thewellbore containing MEMS sensors in order to read data gathered by suchsensors. For example, the interrogator tool may only need to be loweredabout half-way along the vertical length of the wellbore containing MEMSsensors. Alternatively, the interrogator tool may be lowered verticallywithin the wellbore to a location adjacent to a horizontal arm of awell, whereby MEMS sensors located in the horizontal arm may be readwithout the need for the interrogator tool to traverse the horizontalarm. Alternatively, the interrogator tool may be used at or near thesurface and read the data gathered by the sensors distributed along allor a portion of the wellbore. For example, sensors located a distanceaway from the interrogator (e.g., at an opposite end of a length ofcasing or tubing) may communicate via a network formed by the sensors asdescribed previously.

In embodiments, the MEMS sensors are ultra-small, e.g., 3 mm², such thatthey are pumpable in a sealant slurry. In embodiments, the MEMS deviceis approximately 0.01 mm² to 1 mm², alternatively 1 mm² to 3 mm²,alternatively 3 mm² to 5 mm², or alternatively 5 mm² to 10 mm². Inembodiments, the data sensors are capable of providing data throughoutthe cement service life. In embodiments, the data sensors are capable ofproviding data for up to 100 years. In an embodiment, the wellborecomposition comprises an amount of MEMS effective to measure one or moredesired parameters. In various embodiments, the wellbore compositioncomprises an effective amount of MEMS such that sensed readings may beobtained at intervals of about 1 foot, alternatively about 6 inches, oralternatively about 1 inch, along the portion of the wellbore containingthe MEMS. In an embodiment, the MEMS sensors may be present in thewellbore composition in an amount of from about 0.001 to about 10 weightpercent. Alternatively, the MEMS may be present in the wellborecomposition in an amount of from about 0.01 to about 5 weight percent.In embodiments, the sensors may have dimensions (e.g., diameters orother dimensions) that range from nanoscale, e.g., about 1 to 1000 nm(e.g., NEMS), to a micrometer range, e.g., about 1 to 1000 μm (e.g.,MEMS), or alternatively any size from about 1 nm to about 1 mm. Inembodiments, the MEMS sensors may be present in the wellbore compositionin an amount of from about 5 volume percent to about 30 volume percent.

In various embodiments, the size and/or amount of sensors present in awellbore composition (e.g., the sensor loading or concentration) may beselected such that the resultant wellbore servicing composition isreadily pumpable without damaging the sensors and/or without having thesensors undesirably settle out (e.g., screen out) in the pumpingequipment (e.g., pumps, conduits, tanks, etc.) and/or upon placement inthe wellbore. Also, the concentration/loading of the sensors within thewellbore servicing fluid may be selected to provide a sufficient averagedistance between sensors to allow for networking of the sensors (e.g.,daisy-chaining) in embodiments using such networks, as described in moredetail herein. For example, such distance may be a percentage of theaverage communication distance for a given sensor type. By way ofexample, a given sensor having a 2 inch communication range in a givenwellbore composition should be loaded into the wellbore composition inan amount that the average distance between sensors in less than 2inches (e.g., less than 1.9, 1.8, 1.7, 1.6, 1.5, 1.4, 1.3, 1.2, 1.1,1.0, etc. inches). The size of sensors and the amount may be selected sothat they are stable, do not float or sink, in the well treating fluid.The size of the sensor could range from nano size to microns. In someembodiments, the sensors may be nanoelectromechanical systems (NEMS),MEMS, or combinations thereof. Unless otherwise indicated herein, itshould be understood that any suitable micro and/or nano sized sensorsor combinations thereof may be employed. The embodiments disclosedherein should not otherwise be limited by the specific type of microand/or nano sensor employed unless otherwise indicated or prescribed bythe functional requirements thereof, and specifically NEMS may be usedin addition to or in lieu of MEMS sensors in the various embodimentsdisclosed herein.

In embodiments, the MEMS sensors comprise passive (remain unpowered whennot being interrogated) sensors energized by energy radiated from a datainterrogation tool. The data interrogation tool may comprise an energytransceiver sending energy (e.g., radio waves) to and receiving signalsfrom the MEMS sensors and a processor processing the received signals.The signals from the MEMS sensors are received by a sensor assembly thatincludes one or more antennae and one or more sensing circuits. Sensingcircuits includes at least one sensor including a plurality of sensorcoils.

The data interrogation tool may further comprise a memory component, acommunications component, or both. The memory component may store rawand/or processed data received from the MEMS sensors, and thecommunications component may transmit raw data to the processor and/ortransmit processed data to another receiver, for example located at thesurface. The tool components (e.g., transceiver, processor, memorycomponent, and communications component) are coupled together and insignal communication with each other.

In an embodiment, one or more of the data interrogator components may beintegrated into a tool or unit that is temporarily or permanently placeddownhole (e.g., a downhole module), for example prior to, concurrentwith, and/or subsequent to placement of the MEMS sensors in thewellbore. In an embodiment, a removable downhole module comprises atransceiver and a memory component, and the downhole module is placedinto the wellbore, reads data from the MEMS sensors, stores the data inthe memory component, is removed from the wellbore, and the raw data isaccessed. Alternatively, the removable downhole module may have aprocessor to process and store data in the memory component, which issubsequently accessed at the surface when the tool is removed from thewellbore. Alternatively, the removable downhole module may have acommunications component to transmit raw data to a processor and/ortransmit processed data to another receiver, for example located at thesurface. The communications component may communicate via wired orwireless communications. For example, the downhole module maycommunicate with a component or other node on the surface via a networkof MEMS sensors, or cable or other communications/telemetry device suchas a radio frequency, electromagnetic telemetry device or an acoustictelemetry device. The removable downhole module may be intermittentlypositioned downhole via any suitable conveyance, for example wire-line,coiled tubing, straight tubing, gravity, pumping, etc., to monitorconditions at various times during the life of the well.

In embodiments, the data interrogation tool comprises a permanent orsemi-permanent downhole module that remains downhole for extendedperiods of time. For example, a semi-permanent downhole module may beretrieved and data downloaded once every few months or years.Alternatively, a permanent downhole module may remain in the wellthroughout the service life of well. In an embodiment, a permanent orsemi-permanent downhole module comprises a transceiver and a memorycomponent, and the downhole module is placed into the wellbore, readsdata from the MEMS sensors, optionally stores the data in the memorycomponent, and transmits the read and optionally stored data to thesurface. Alternatively, the permanent or semi-permanent downhole modulemay have a processor to process and sensed data into processed data,which may be stored in memory and/or transmit to the surface. Thepermanent or semi-permanent downhole module may have a communicationscomponent to transmit raw data to a processor and/or transmit processeddata to another receiver, for example located at the surface. Thecommunications component may communicate via wired or wirelesscommunications. For example, the downhole module may communicate with acomponent or other node on the surface via a network of MEMS sensors, ora cable or other communications/telemetry device such as a radiofrequency, electromagnetic telemetry device or an acoustic telemetrydevice.

In embodiments, the data interrogation tool comprises an RF energysource incorporated into its internal circuitry and the data sensors arepassively energized using an RF antenna, which picks up energy from theRF energy source. In an embodiment, the data interrogation tool isintegrated with an RF transceiver.

In an embodiment, the data interrogation tool traverses within a casingin the well and reads MEMS sensors located in a wellbore servicing fluidor composition, for example a sealant (e.g., cement) sheath surroundingthe casing, located in the annular space between the casing and thewellbore wall. In embodiments, the interrogator senses the MEMS sensorswhen in close proximity with the sensors, typically via traversing aremovable downhole component along a length of the wellbore comprisingthe MEMS sensors. In an embodiment, close proximity comprises a radialdistance from a point within the casing to a planar point within anannular space between the casing and the wellbore. In embodiments, closeproximity comprises a distance of 0.01 to 1 meter. According to oneembodiment, close proximity is less than 0.75 meters, for example, lessthan 0.6 meters, for example from about 0.01 to about 0.4 meters. Inthis embodiment, any type of MEMS may be used; however, this embodimentis particularly useful when using passive RFID MEMS. In otherembodiments, the MEMS sensors (e.g., MEMS/RFID sensors) may be empoweredand interrogated by the RF transceiver from a distance, for example adistance of greater than 1 meter, for example, greater than 10 m, oralternatively from the surface or from an adjacent offset well.

The frequency at which the transceiver interrogates the sensor and thedistance between the interrogation tool and the sensor are selectedbased upon the type of MEMS used and the environmental characteristics.According to embodiments, the transceiver interrogates the sensor withRF energy at a frequency between 380 to 650 MHz and in close proximity,e.g., between about 0.1 m to about 0.6 m.

In embodiments, the MEMS sensors incorporated into wellbore cement andused to collect data during and/or after cementing the wellbore. Thedata interrogation tool may be positioned downhole prior to and/orduring cementing, for example integrated into a component such ascasing, casing attachment, plug, cement shoe, or expanding device.Alternatively, the data interrogation tool is positioned downhole uponcompletion of cementing, for example conveyed downhole via wireline. Thecementing methods disclosed herein may optionally comprise the step offoaming the cement composition using a gas such as nitrogen or air. Thefoamed cement compositions may comprise a foaming surfactant andoptionally a foaming stabilizer. The MEMS sensors may be incorporatedinto a sealant composition and placed downhole, for example duringprimary cementing (e.g., conventional or reverse circulation cementing),secondary cementing (e.g., squeeze cementing), or other sealingoperation (e.g., behind an expandable casing).

In primary cementing, cement is positioned in a wellbore to isolate anadjacent portion of the subterranean formation and provide support to anadjacent conduit (e.g., casing). The cement forms a barrier thatprevents fluids (e.g., water or hydrocarbons) In the subterraneanformation from migrating into adjacent zones or other subterraneanformations. In embodiments, the wellbore in which the cement ispositioned belongs to a horizontal or multilateral wellboreconfiguration. It is to be understood that a multilateral wellboreconfiguration includes at least two principal wellbores connected by oneor more ancillary wellbores.

FIG. 2, which shows a typical onshore oil or gas drilling rig andwellbore, will be used to clarify the methods of the present disclosure,with the understanding that the present disclosure is likewiseapplicable to offshore rigs and wellbores. Rig 12 is centered over asubterranean oil or gas formation 14 located below the earth's surface16. Rig 12 includes a work deck 32 that supports a derrick 34. Derrick34 supports a hoisting apparatus 36 for raising and lowering pipestrings such as casing 20. Pump 30 is capable of pumping a variety ofwellbore compositions (e.g., drilling fluid or cement) into the well andincludes a pressure measurement device that provides a pressure readingat the pump discharge. Wellbore 18 has been drilled through the variousearth strata, including formation 14. Upon completion of wellboredrilling, casing 20 is often placed in the wellbore 18 to facilitate theproduction of oil and gas from the formation 14. Casing 20 is a stringof pipes that extends down wellbore 18, through which oil and gas willeventually be extracted. A cement or casing shoe 22 is typicallyattached to the end of the casing string when the casing string is runinto the wellbore. Casing shoe 22 guides casing 20 toward the center ofthe hole and minimizes problems associated with hitting rock ledges orwashouts in wellbore 18 as the casing string is lowered into the well.Casing shoe, 22, may be a guide shoe or a float shoe, and typicallycomprises a tapered, often bullet-nosed piece of equipment found on thebottom of casing string 20. Casing shoe, 22, may be a float shoe fittedwith an open bottom and a valve that serves to prevent reverse flow, orU-tubing, of cement slurry from annulus 26 into casing 20 as casing 20is run into wellbore 18. The region between casing 20 and the wall ofwellbore 18 is known as the casing annulus 26. To fill up casing annulus26 and secure casing 20 in place, casing 20 is usually “cemented” inwellbore 18, which is referred to as “primary cementing.” A datainterrogator tool 40 is shown in the wellbore 18.

In an embodiment, the method of this disclosure is used for monitoringprimary cement during and/or subsequent to a conventional primarycementing operation. In this conventional primary cementing embodiment,MEMS sensors are mixed into a cement slurry, block 102 of FIG. 1, andthe cement slurry is then pumped down the inside of casing 20, block 104of FIG. 1. As the slurry reaches the bottom of casing 20, it flows outof casing 20 and into casing annulus 26 between casing 20 and the wallof wellbore 18. As cement slurry flows up annulus 26, it displaces anyfluid in the wellbore. To ensure no cement remains inside casing 20,devices called “wipers” may be pumped by a wellbore servicing fluid(e.g., drilling mud) through casing 20 behind the cement. As describedin more detail herein, the wellbore servicing fluids such as the cementslurry and/or wiper conveyance fluid (e.g., drilling mud) may containMEMS sensors which aid in detection and/or positioning of the wellboreservicing fluid and/or a mechanical component such as a wiper plug,casing shoe, etc. The wiper contacts the inside surface of casing 20 andpushes any remaining cement out of casing 20. When cement slurry reachesthe earth's surface 16, and annulus 26 is filled with slurry, pumping isterminated and the cement is allowed to set. The MEMS sensors of thepresent disclosure may also be used to determine one or more parametersduring placement and/or curing of the cement slurry. Also, the MEMSsensors of the present disclosure may also be used to determinecompletion of the primary cementing operation, as further discussedherein below.

Referring back to FIG. 1, during cementing, or subsequent the setting ofcement, a data interrogation tool may be positioned in wellbore 18, asat block 106 of FIG. 1. For example, the wiper may be equipped with adata interrogation tool and may read data from the MEMS while beingpumped downhole and transmit same to the surface. Alternatively, aninterrogator tool may be run into the wellbore following completion ofcementing a segment of casing, for example as part of the drill stringduring resumed drilling operations. Alternatively, the interrogator toolmay be run downhole via a wireline or other conveyance. The datainterrogation tool may then be signaled to interrogate the sensors(block 108 of FIG. 1) whereby the sensors are activated to record and/ortransmit data, block 110 of FIG. 1. The data interrogation toolcommunicates the data to a processor 112 whereby data sensor (andlikewise cement slurry) position and cement integrity may be determinedvia analyzing sensed parameters for changes, trends, expected values,etc. For example, such data may reveal conditions that may be adverse tocement curing. The sensors may provide a temperature profile over thelength of the cement sheath, with a uniform temperature profile likewiseindicating a uniform cure (e.g., produced via heat of hydration of thecement during curing) or a change in temperature might indicate theinflux of formation fluid (e.g., presence of water and/or hydrocarbons)that may degrade the cement during the transition from slurry to setcement. Alternatively, such data may indicate a zone of reduced,minimal, or missing sensors, which would indicate a loss of cementcorresponding to the area (e.g., a loss/void zone or waterinflux/washout). Such methods may be available with various cementtechniques described herein such as conventional or reverse primarycementing.

Due to the high pressure at which the cement is pumped duringconventional primary cementing (pump down the casing and up theannulus), fluid from the cement slurry may leak off into existing lowpressure zones traversed by the wellbore. This may adversely affect thecement, and incur undesirable expense for remedial cementing operations(e.g., squeeze cementing as discussed below) to position the cement inthe annulus. Such leak off may be detected via the present disclosure asdescribed previously. Additionally, conventional circulating cementingmay be time-consuming, and therefore relatively expensive, becausecement is pumped all the way down casing 20 and back up annulus 26.

One method of avoiding problems associated with conventional primarycementing is to employ reverse circulation primary cementing. Reversecirculation cementing is a term of art used to describe a method where acement slurry is pumped down casing annulus 26 instead of into casing20. The cement slurry displaces any fluid as it is pumped down annulus26. Fluid in the annulus is forced down annulus 26, into casing 20(along with any fluid in the casing), and then back up to earth'ssurface 16. When reverse circulation cementing, casing shoe 22 comprisesa valve that is adjusted to allow flow into casing 20 and then sealedafter the cementing operation is complete. Once slurry is pumped to thebottom of casing 20 and fills annulus 26, pumping is terminated and thecement is allowed to set in annulus 26. Examples of reverse cementingapplications are disclosed in U.S. Pat. Nos. 6,920,929 and 6,244,342,each of which is incorporated herein by reference in its entirety.

In embodiments of the present disclosure, sealant slurries comprisingMEMS data sensors are pumped down the annulus in reverse circulationapplications, a data interrogator is located within the wellbore (e.g.,integrated into the casing shoe) and sealant performance is monitored asdescribed with respect to the conventional primary sealing methoddisclosed hereinabove. Additionally, the data sensors of the presentdisclosure may also be used to determine completion of a reversecirculation operation, as further discussed below.

Secondary cementing within a wellbore may be carried out subsequent toprimary cementing operations. A common example of secondary cementing issqueeze cementing wherein a sealant such as a cement composition isforced under pressure into one or more permeable zones within thewellbore to seal such zones. Examples of such permeable zones includefissures, cracks, fractures, streaks, flow channels, voids, highpermeability streaks, annular voids, or combinations thereof. Thepermeable zones may be present in the cement column residing in theannulus, a wall of the conduit in the wellbore, a microannulus betweenthe cement column and the subterranean formation, and/or a microannulusbetween the cement column and the conduit. The sealant (e.g., secondarycement composition) sets within the permeable zones, thereby forming ahard mass to plug those zones and prevent fluid from passingtherethrough (i.e., prevents communication of fluids between thewellbore and the formation via the permeable zone). Various proceduresthat may be followed to use a sealant composition in a wellbore aredescribed in U.S. Pat. No. 5,346,012, which is incorporated by referenceherein in its entirety. In various embodiments, a sealant compositioncomprising MEMS sensors is used to repair holes, channels, voids, andmicroannuli in casing, cement sheath, gravel packs, and the like asdescribed in U.S. Pat. Nos. 5,121,795; 5,123,487; and 5,127,473, each ofwhich is incorporated by reference herein in its entirety.

In embodiments, the method of the present disclosure may be employed ina secondary cementing operation. In these embodiments, data sensors aremixed with a sealant composition (e.g., a secondary cement slurry) atblock 102 of FIG. 1 and subsequent or during positioning and hardeningof the cement, the sensors are interrogated to monitor the performanceof the secondary cement in an analogous manner to the incorporation andmonitoring of the data sensors in primary cementing methods disclosedhereinabove. For example, the MEMS sensors may be used to verify thatthe secondary sealant is functioning properly and/or to monitor itslong-term integrity.

In embodiments, the methods of the present disclosure are utilized formonitoring cementitious sealants (e.g., hydraulic cement),non-cementitious (e.g., polymer, latex or resin systems), orcombinations thereof, which may be used in primary, secondary, or othersealing applications. For example, expandable tubulars such as pipe,pipe string, casing, liner, or the like are often sealed in asubterranean formation. The expandable tubular (e.g., casing) is placedin the wellbore, a sealing composition is placed into the wellbore, theexpandable tubular is expanded, and the sealing composition is allowedto set in the wellbore. For example, after expandable casing is placeddownhole, a mandrel may be run through the casing to expand the casingdiametrically, with expansions up to 25% possible. The expandabletubular may be placed in the wellbore before or after placing thesealing composition in the wellbore. The expandable tubular may beexpanded before, during, or after the set of the sealing composition.When the tubular is expanded during or after the set of the sealingcomposition, resilient compositions will remain competent due to theirelasticity and compressibility. Additional tubulars may be used toextend the wellbore into the subterranean formation below the firsttubular as is known to those of skill in the art. Sealant compositionsand methods of using the compositions with expandable tubulars aredisclosed in U.S. Pat. Nos. 6,722,433 and 7,040,404 and U.S. Pat. Pub.No. 2004/0167248, each of which is incorporated by reference herein inits entirety. In expandable tubular embodiments, the sealants maycomprise compressible hydraulic cement compositions and/ornon-cementitious compositions.

Compressible hydraulic cement compositions have been developed whichremain competent (continue to support and seal the pipe) whencompressed, and such compositions may comprise MEMS sensors. The sealantcomposition is placed in the annulus between the wellbore and the pipeor pipe string, the sealant is allowed to harden into an impermeablemass, and thereafter, the expandable pipe or pipe string is expandedwhereby the hardened sealant composition is compressed. In embodiments,the compressible foamed sealant composition comprises a hydrauliccement, a rubber latex, a rubber latex stabilizer, a gas and a mixtureof foaming and foam stabilizing surfactants. Suitable hydraulic cementsinclude, but are not limited to, Portland cement and calcium aluminatecement.

Often, non-cementitious resilient sealants with comparable strength tocement, but greater elasticity and compressibility, are required forcementing expandable casing. In embodiments, these sealants comprisepolymeric sealing compositions, and such compositions may comprise MEMSsensors. In an embodiment, the sealants composition comprises a polymerand a metal containing compound. In embodiments, the polymer comprisescopolymers, terpolymers, and interpolymers. The metal-containingcompounds may comprise zinc, tin, iron, selenium magnesium, chromium, orcadmium. The compounds may be in the form of an oxide, carboxylic acidsalt, a complex with dithiocarbamate ligand, or a complex withmercaptobenzothiazole ligand. In embodiments, the sealant comprises amixture of latex, dithio carbamate, zinc oxide, and sulfur.

In embodiments, the methods of the present disclosure comprise addingdata sensors to a sealant to be used behind expandable casing to monitorthe integrity of the sealant upon expansion of the casing and during theservice life of the sealant. In this embodiment, the sensors maycomprise MEMS sensors capable of measuring, for example, moisture and/ortemperature change. If the sealant develops cracks, water influx maythus be detected via moisture and/or temperature indication.

In an embodiment, the MEMS sensors are added to one or more wellboreservicing compositions used or placed downhole in drilling or completinga monodiameter wellbore as disclosed in U.S. Pat. No. 7,066,284 and U.S.Pat. Pub. No. 2005/0241855, each of which is incorporated by referenceherein in its entirety. In an embodiment, the MEMS sensors are includedin a chemical casing composition used in a monodiameter wellbore. Inanother embodiment, the MEMS sensors are included in compositions (e.g.,sealants) used to place expandable casing or tubulars in a monodiameterwellbore. Examples of chemical casings are disclosed in U.S. Pat. Nos.6,702,044; 6,823,940; and 6,848,519, each of which is incorporatedherein by reference in its entirety.

In one embodiment, the MEMS sensors are used to gather data, e.g.,sealant data, and monitor the long-term integrity of the wellborecomposition, e.g., sealant composition, placed in a wellbore, forexample a wellbore for the recovery of natural resources such as wateror hydrocarbons or an injection well for disposal or storage. In anembodiment, data/information gathered and/or derived from MEMS sensorsin a downhole wellbore composition e.g., sealant composition, comprisesat least a portion of the input and/or output to into one or morecalculators, simulations, or models used to predict, select, and/ormonitor the performance of wellbore compositions e.g., sealantcompositions, over the life of a well. Such models and simulators may beused to select a wellbore composition, e.g., sealant composition,comprising MEMS for use in a wellbore. After placement in the wellbore,the MEMS sensors may provide data that can be used to refine,recalibrate, or correct the models and simulators. Furthermore, the MEMSsensors can be used to monitor and record the downhole conditions thatthe composition, e.g., sealant, is subjected to, and composition, e.g.,sealant, performance may be correlated to such long term data to providean indication of problems or the potential for problems in the same ordifferent wellbores. In various embodiments, data gathered from MEMSsensors is used to select a wellbore composition, e.g., sealantcomposition, or otherwise evaluate or monitor such sealants, asdisclosed in U.S. Pat. Nos. 6,697,738; 6,922,637; and 7,133,778, each ofwhich is incorporated by reference herein in its entirety.

In an embodiment, the compositions and methodologies of this disclosureare employed in an operating environment that generally comprises awellbore that penetrates a subterranean formation for the purpose ofrecovering hydrocarbons, storing hydrocarbons, injection of carbondioxide, storage of carbon dioxide, disposal of carbon dioxide, and thelike, and the MEMS located downhole (e.g., within the wellbore and/orsurrounding formation) may provide information as to a condition and/orlocation of the composition and/or the subterranean formation. Forexample, the MEMS may provide information as to a location, flowpath/profile, volume, density, temperature, pressure, or a combinationthereof of a hydrocarbon (e.g., natural gas stored in a salt dome) orcarbon dioxide placed in a subterranean formation such thateffectiveness of the placement may be monitored and evaluated, forexample detecting leaks, determining remaining storage capacity in theformation, etc. In some embodiments, the compositions of this disclosureare employed in an enhanced oil recovery operation wherein a wellborethat penetrates a subterranean formation may be subjected to theInjection of gases (e.g., carbon dioxide) so as to improve hydrocarbonrecovery from said wellbore, and the MEMS may provide information as toa condition and/or location of the composition and/or the subterraneanformation. For example, the MEMS may provide information as to alocation, flow path/profile, volume, density, temperature, pressure, ora combination thereof of carbon dioxide used in a carbon dioxideflooding enhanced oil recovery operation in real time such that theeffectiveness of such operation may be monitored and/or adjusted in realtime during performance of the operation to improve the result of same.

Referring to FIG. 4, a method 200 for selecting a sealant (e.g., acementing composition) for sealing a subterranean zone penetrated by awellbore according to the present embodiment basically comprisesdetermining a group of effective compositions from a group ofcompositions given estimated conditions experienced during the life ofthe well, and estimating the risk parameters for each of the group ofeffective compositions. In an alternative embodiment, actual measuredconditions experienced during the life of the well, in addition to or inlieu of the estimated conditions, may be used. Such actual measuredconditions may be obtained for example via sealant compositionscomprising MEMS sensors as described herein. Effectivenessconsiderations include concerns that the sealant composition be stableunder downhole conditions of pressure and temperature, resist downholechemicals, and possess the mechanical properties to withstand stressesfrom various downhole operations to provide zonal isolation for the lifeof the well.

In step 212, well input data for a particular well is determined. Wellinput data includes routinely measurable or calculable parametersinherent in a well, including vertical depth of the well, overburdengradient, pore pressure, maximum and minimum horizontal stresses, holesize, casing outer diameter, casing inner diameter, density of drillingfluid, desired density of sealant slurry for pumping, density ofcompletion fluid, and top of sealant. As will be discussed in greaterdetail with reference to step 214, the well can be computer modeled. Inmodeling, the stress state in the well at the end of drilling, andbefore the sealant slurry is pumped into the annular space, affects thestress state for the interface boundary between the rock and the sealantcomposition. Thus, the stress state in the rock with the drilling fluidis evaluated, and properties of the rock such as Young's modulus,Poisson's ratio, and yield parameters are used to analyze the rockstress state. These terms and their methods of determination are wellknown to those skilled in the art. It is understood that well input datawill vary between individual wells. In an alternative embodiment, wellinput data includes data that is obtained via sealant compositionscomprising MEMS sensors as described herein.

In step 214, the well events applicable to the well are determined. Forexample, cement hydration (setting) is a well event. Other well eventsinclude pressure testing, well completions, hydraulic fracturing,hydrocarbon production, fluid injection, perforation, subsequentdrilling, formation movement as a result of producing hydrocarbons athigh rates from unconsolidated formation, and tectonic movement afterthe sealant composition has been pumped in place. Well events includethose events that are certain to happen during the life of the well,such as cement hydration, and those events that are readily predicted tooccur during the life of the well, given a particular well's location,rock type, and other factors well known in the art. In an embodiment,well events and data associated therewith may be obtained via sealantcompositions comprising MEMS sensors as described herein.

Each well event is associated with a certain type of stress, forexample, cement hydration is associated with shrinkage, pressure testingis associated with pressure, well completions, hydraulic fracturing, andhydrocarbon production are associated with pressure and temperature,fluid injection is associated with temperature, formation movement isassociated with load, and perforation and subsequent drilling areassociated with dynamic load. As can be appreciated, each type of stresscan be characterized by an equation for the stress state (collectively“well event stress states”), as described in more detail in U.S. Pat.No. 7,133,778 which is incorporated herein by reference in its entirety.

In step 216, the well input data, the well event stress states, and thesealant data are used to determine the effect of well events on theintegrity of the sealant sheath during the life of the well for each ofthe sealant compositions. The sealant compositions that would beeffective for sealing the subterranean zone and their capacity from itselastic limit are determined. In an alternative embodiment, theestimated effects over the life of the well are compared to and/orcorrected in comparison to corresponding actual data gathered over thelife of the well via sealant compositions comprising MEMS sensors asdescribed herein. Step 216 concludes by determining which sealantcompositions would be effective in maintaining the integrity of theresulting cement sheath for the life of the well.

In step 218, parameters for risk of sealant failure for the effectivesealant compositions are determined. For example, even though a sealantcomposition is deemed effective, one sealant composition may be moreeffective than another. In one embodiment, the risk parameters arecalculated as percentages of sealant competency during the determinationof effectiveness in step 216. In an alternative embodiment, the riskparameters are compared to and/or corrected in comparison to actual datagathered over the life of the well via sealant compositions comprisingMEMS sensors as described herein.

Step 218 provides data that allows a user to perform a cost benefitanalysis. Due to the high cost of remedial operations, it is importantthat an effective sealant composition is selected for the conditionsanticipated to be experienced during the life of the well. It isunderstood that each of the sealant compositions has a readilycalculable monetary cost. Under certain conditions, several sealantcompositions may be equally efficacious, yet one may have the addedvirtue of being less expensive. Thus, it should be used to minimizecosts. More commonly, one sealant composition will be more efficacious,but also more expensive. Accordingly, in step 220, an effective sealantcomposition with acceptable risk parameters is selected given thedesired cost. Furthermore, the overall results of steps 200-220 can becompared to actual data that is obtained via sealant compositionscomprising MEMS sensors as described herein, and such data may be usedto modify and/or correct the inputs and/or outputs to the various steps200-220 to improve the accuracy of same.

As discussed above and with reference to FIG. 2, wipers are oftenutilized during conventional primary cementing to force cement slurryout of the casing. The wiper plug also serves another purpose:typically, the end of a cementing operation is signaled when the wiperplug contacts a restriction (e.g., casing shoe) inside the casing 20 atthe bottom of the string. When the plug contacts the restriction, asudden pressure increase at pump 30 is registered. In this way, it canbe determined when the cement has been displaced from the casing 20 andfluid flow returning to the surface via casing annulus 26 stops.

In reverse circulation cementing, it is also necessary to correctlydetermine when cement slurry completely fills the annulus 26. Continuingto pump cement into annulus 26 after cement has reached the far end ofannulus 26 forces cement into the far end of casing 20, which couldincur lost time if cement must be drilled out to continue drillingoperations.

The methods disclosed herein may be utilized to determine when cementslurry has been appropriately positioned downhole. Furthermore, asdiscussed below, the methods of the present disclosure may additionallycomprise using a MEMS sensor to actuate a valve or other mechanicalmeans to close and prevent cement from entering the casing upondetermination of completion of a cementing operation.

The way in which the method of the present disclosure may be used tosignal when cement is appropriately positioned within annulus 26 willnow be described within the context of a reverse circulation cementingoperation. FIG. 3 is a flowchart of a method for determining completionof a cementing operation and optionally further actuating a downholetool upon completion (or to initiate completion) of the cementingoperation. This description will reference the flowchart of FIG. 3, aswell as the wellbore depiction of FIG. 2.

At block 130, a data interrogation tool as described hereinabove ispositioned at the far end of casing 20. In an embodiment, the datainterrogation tool is incorporated with or adjacent to a casing shoepositioned at the bottom end of the casing and in communication withoperators at the surface. At block 132, MEMS sensors are added to afluid (e.g., cement slurry, spacer fluid, displacement fluid, etc.) tobe pumped into annulus 26. At block 134, cement slurry is pumped intoannulus 26. In an embodiment, MEMS sensors may be placed insubstantially all of the cement slurry pumped into the wellbore. In analternative embodiment, MEMS sensors may be placed in a leading plug orotherwise placed in an initial portion of the cement to indicate aleading edge of the cement slurry. In an embodiment, MEMS sensors areplaced in leading and trailing plugs to signal the beginning and end ofthe cement slurry. While cement is continuously pumped into annulus 26,at decision 136, the data interrogation tool is attempting to detectwhether the data sensors are in communicative (e.g., close) proximitywith the data interrogation tool. As long as no data sensors aredetected, the pumping of additional cement into the annulus continues.When the data interrogation tool detects the sensors at block 138indicating that the leading edge of the cement has reached the bottom ofthe casing, the interrogator sends a signal to terminate pumping. Thecement in the annulus is allowed to set and form a substantiallyimpermeable mass which physically supports and positions the casing inthe wellbore and bonds the casing to the walls of the wellbore in block148.

If the fluid of block 130 is the cement slurry, MEMS-based data sensorsare incorporated within the set cement, and parameters of the cement(e.g., temperature, pressure, ion concentration, stress, strain, etc.)can be monitored during placement and for the duration of the servicelife of the cement according to methods disclosed hereinabove.Alternatively, the data sensors may be added to an interface fluid(e.g., spacer fluid or other fluid plug) introduced into the annulusprior to and/or after introduction of cement slurry into the annulus.

The method just described for determination of the completion of aprimary wellbore cementing operation may further comprise the activationof a downhole tool. For example, at block 130, a valve or other tool maybe operably associated with a data interrogator tool at the far end ofthe casing. This valve may be contained within float shoe 22, forexample, as disclosed hereinabove. Again, float shoe 22 may contain anintegral data interrogator tool, or may otherwise be coupled to a datainterrogator tool. For example, the data interrogator tool may bepositioned between casing 20 and float shoe 22. Following the methodpreviously described and blocks 132 to 136, pumping continues as thedata interrogator tool detects the presence or absence of data sensorsin close proximity to the interrogator tool (dependent upon the specificmethod cementing method being employed, e.g., reverse circulation, andthe positioning of the sensors within the cement flow). Upon detectionof a determinative presence or absence of sensors in close proximityindicating the termination of the cement slurry, the data interrogatortool sends a signal to actuate the tool (e.g., valve) at block 140. Atblock 142, the valve closes, sealing the casing and preventing cementfrom entering the portion of casing string above the valve in a reversecementing operation. At block 144, the closing of the valve at 142,causes an increase in back pressure that is detected at the hydraulicpump 30. At block 146, pumping is discontinued, and cement is allowed toset in the annulus at block 148. In embodiments wherein data sensorshave been incorporated throughout the cement, parameters of the cement(and thus cement integrity) can additionally be monitored duringplacement and for the duration of the service life of the cementaccording to methods disclosed hereinabove.

In embodiments, systems for sensing, communicating and evaluatingwellbore parameters may include the wellbore 18; the casing 20 or otherworkstring, toolstring, production string, tubular, coiled tubing,wireline, or any other physical structure or conveyance extendingdownhole from the surface; MEMS sensors 52 that may be placed into thewellbore 18 and/or surrounding formation 14, for example, via a wellboreservicing fluid; and a device or plurality of devices for interrogatingthe MEMS sensors 52 to gather/collect data generated by the MEMS sensors52, for transmitting the data from the MEMS sensors 52 to the earth'ssurface 16, for receiving communications and/or data to the earth'ssurface, for processing the data, or any combination thereof, referredto collectively herein a data interrogation/communication assembly unitsor in some instances as a data interrogator or data interrogation tool.Unless otherwise specified, it is understood that such devices asdisclosed in the various embodiments herein will have MEMS sensorinterrogation functionality, communication functionality (e.g.,transceiver functionality), or both, as will be apparent from theparticular embodiments and associated context disclosed herein.

The wellbore servicing fluid comprising the MEMS sensors 52 may comprisea drilling fluid, a spacer fluid, a sealant, a fracturing fluid, agravel pack fluid, a completion fluid, or any other fluid placeddownhole. In addition, the MEMS sensors 52 may be configured to measurephysical parameters such as temperature, stress and strain, as well aschemical parameters such as CO₂ concentration, H₂S concentration, CH₄concentration, moisture content, pH, Na⁺ concentration, K⁺concentration, and Cl⁻ concentration. Various embodiments describedherein are directed to interrogation/communication assembly units thatare dispersed or distributed at intervals along a length of the casing20 and form a communication network for transmitting and/or receivingcommunications to/from a location downhole and the surface, with thefurther understanding that the interrogation/communication assemblyunits may be otherwise physically supported by a workstring, toolstring,production string, tubular, coiled tubing, wireline, or any otherphysical structure or conveyance extending downhole from the surface.

Referring to FIG. 5, a schematic view of an embodiment of a wellboreparameter sensing system 600 is illustrated. The wellbore parametersensing system 600 may comprise the wellbore 18, inside which the casing20 is situated. In an embodiment, the wellbore parameter sensing system600 may further comprise a plurality of regional communication assemblyunits 610, which may be situated on the casing 20 and spaced at regularor irregular intervals along the casing, e.g., about every 5 m to 15 malong the length of the casing 20, alternatively about every 8 m to 12 malong the length of the casing 20, alternatively about every 10 m alongthe length of the casing 20. In embodiments, the regional communicationassembly units 610 may be situated on or in casing collars that couplecasing joints together. In addition, the regional communication assemblyunits 610 may be situated in an interior of the casing 20, on anexterior of the casing 20, or both. In an embodiment, the wellboreparameter sensing system 600 may further comprise a tool (e.g., a datainterrogator 620 or other data collection and/or power-providingdevice), which may be lowered down into the wellbore 18 on a wireline622, as well as a processor 630 or other data storage or communicationdevice, which is connected to the data interrogator 620.

In an embodiment, each regional communication assembly unit 610 may beconfigured to interrogate and/or receive data from, MEMS sensors 52situated in the annulus 26, in the vicinity of the regionalcommunication assembly unit 610, whereby the vicinity of the regionalcommunication assembly unit 610 is defined as in the above discussion ofthe wellbore parameter sensing system 600 illustrated in FIG. 5. TheMEMS sensors 52 may be configured to transmit MEMS sensor data toneighboring MEMS sensors 52, as denoted by double arrows 632, as well asto transmit MEMS sensor data to the regional communication assemblyunits 610 in their respective vicinities, as denoted by single arrows634. In an embodiment, the MEMS sensors 52 may be passive sensors thatare powered by bursts of electromagnetic radiation from the regionalcommunication units 610. In a further embodiment, the MEMS sensors 52may be active sensors that are powered by batteries situated in or onthe MEMS sensors 52 or by other downhole power sources.

The regional communication assembly units 610 in the present embodimentof the wellbore parameter sensing system 600 are neither wired to oneanother, nor wired to the processor 630 or other surface equipment.Accordingly, in an embodiment, the regional communication assembly units610 may be powered by batteries, which enable the regional communicationassembly units 610 to interrogate the MEMS sensors 52 in theirrespective vicinities and/or receive MEMS sensor data from the MEMSsensors 52 in their respective vicinities. The batteries of the regionalcommunication assembly units 610 may be inductively rechargeable by thedata interrogator 620 or may be rechargeable by other downhole powersources. In addition, as set forth above, the data interrogator 620 maybe lowered into the wellbore 18 for the purpose of interrogatingregional communication assembly units 610 and receiving the MEMS sensordata stored in the regional communication units 610. Furthermore, thedata interrogator 620 may be configured to transmit the MEMS sensor datato the processor 630, which processes the MEMS sensor data. In anembodiment, a fluid containing MEMS in contained within the wellborecasing (for example, as shown in FIGS. 5, 6, 7, and 10), and the datainterrogator 620 is conveyed through such fluid and into communicativeproximity with the regional communication assembly units 610. In variousembodiments, the data interrogator 620 may communicate with, power up,and/or gather data directly from the various MEMS sensors distributedwithin the annulus 26 and/or the casing 20, and such direct interactionwith the MEMS sensors may be in addition to or in lieu of communicationwith one or more of the regional communication assembly units 610. Forexample, if a given regional communication assembly unit 610 experiencesan operational failure, the data interrogator 620 may directlycommunicate with the MEMS within the given region experiencing thefailure, and thereby serve as a backup (or secondary/verification) datacollection option.

Referring to FIG. 6, a schematic view of an embodiment of a wellboreparameter sensing system 700 is illustrated. As in earlier-describedembodiments, the wellbore parameter sensing system 700 comprises thewellbore 18 and the casing 20 that is situated inside the wellbore 18.In addition, as in the case of other embodiments illustrated in FIG. 5,the wellbore parameter sensing system 700 comprises a plurality ofregional communication assembly units 710, which may be situated on thecasing 20 and spaced at regular or irregular intervals along the casing,e.g., about every 5 m to 15 m along the length of the casing 20,alternatively about every 8 m to 12 m along the length of the casing 20,alternatively about every 10 m along the length of the casing 20. Inembodiments, the regional communication assembly units 710 may besituated on or in casing collars that couple casing joints together. Inaddition, the regional communication assembly units 710 may be situatedin an interior of the casing 20, on an exterior of the casing 20, orboth, or may be otherwise located and supported as described in variousembodiments herein.

In one embodiment, the wellbore parameter sensing system 700 furthercomprises one or more primary (or master) communication units 720. Theregional communication units 710 a and the primary communicationassembly unit 720 a may be coupled to one another by a data line 730,which allows sensor data obtained by the regional communication assemblyunits 710 a from MEMS sensors 52 situated in the annulus 26 to betransmitted from the regional communication units 710 a to the primarycommunication unit 720 a, as indicated by directional arrows 732.

In an embodiment, the MEMS sensors 52 may sense at least one wellboreparameter and transmit data regarding the at least one wellboreparameter to the regional communication assembly units 710 b, either vianeighboring MEMS sensors 52 as denoted by double arrow 734, or directlyto the regional communication assembly units 710 as denoted by singlearrows 736. The regional communication assembly units 710 b maycommunicate wirelessly with the primary or master communication assemblyunit 720 b, which may in turn communicate wirelessly with equipmentlocated at the surface (or via telemetry such as casing signaltelemetry) and/or other regional communication assembly units 720 aand/or other primary or master communication assembly units 720 a.

In embodiments, the primary or master communication assembly units 720gather information from the MEMS sensors and transmit (e.g., wirelessly,via wire, via telemetry such as casing signal telemetry, etc.) suchinformation to equipment (e.g., processor 750) located at the surface.

In an embodiment, the wellbore parameter sensing system 700 furthercomprises, additionally or alternatively, a data interrogator 740, whichmay be lowered into the wellbore 18 via a wire line 742, as well as aprocessor 750, which is connected to the data interrogator 740. In anembodiment, the data interrogator 740 is suspended adjacent to theprimary communication unit 720, interrogates the primary communicationassembly unit 720, receives MEMS sensor data collected by all of theregional communication assembly units 710 and transmits the MEMS sensordata to the processor 750 for processing. The data interrogator 740 mayprovide other functions, for example as described with reference to datainterrogator 620 of FIG. 5. In various embodiments, the datainterrogator 740 (and likewise the data interrogator 620) maycommunicate directly or indirectly with any one or more of the MEMSsensors (e.g., sensors 52), local or regional datainterrogation/communication assembly units (e.g., units 310, 510, 610,710), primary or master communication assembly units (e.g., units 720),or any combination thereof.

Referring to FIG. 7, a schematic view of an embodiment of a wellboreparameter sensing system 800 is illustrated. As in earlier-describedembodiments, the wellbore parameter sensing system 800 comprises thewellbore 18 and the casing 20 that is situated inside the wellbore 18.In addition, as in the case of other embodiments shown in FIGS. 5 and 6,the wellbore parameter sensing system 800 comprises a plurality oflocal, regional, and/or primary/master communication assembly units 810,which may be situated on the casing 20 and spaced at regular orirregular intervals along the casing 20, e.g., about every 5 m to 15 malong the length of the casing 20, alternatively about every 8 m to 12 malong the length of the casing 20, alternatively about every 10 m alongthe length of the casing 20. In embodiments, the communication assemblyunits 810 may be situated on or in casing collars that couple casingjoints together. In addition, the communication assembly units 810 maybe situated in an interior of the casing 20, on an exterior of thecasing 20, or both, or may be otherwise located and supported asdescribed in various embodiments herein.

In an embodiment, MEMS sensors 52, which are present in a wellboreservicing fluid that has been placed in the wellbore 18, may sense atleast one wellbore parameter and transmit data regarding the at leastone wellbore parameter to the local, regional, and/or primary/mastercommunication assembly units 810, either via neighboring MEMS sensors 52as denoted by double arrows 812, 814, or directly to the communicationassembly units 810 as denoted by single arrows 816, 818.

In an embodiment, the wellbore parameter sensing system 800 may furthercomprise a data interrogator 820, which is connected to a processor 830and is configured to interrogate each of the communication assemblyunits 810 for MEMS sensor data via a ground penetrating signal 822 andto transmit the MEMS sensor data to the processor 830 for processing.

In a further embodiment, one or more of the communication assembly units810 may be coupled together by a data line (e.g., wired communications).In this embodiment, the MEMS sensor data collected from the MEMS sensors52 by the regional communication assembly units 810 may be transmittedvia the data line to, for example, the regional communication assemblyunit 810 situated furthest uphole. In this case, only one regionalcommunication assembly unit 810 is interrogated by the surface locateddata interrogator 820. In addition, since the regional communicationassembly unit 810 receiving all of the MEMS sensor data is situateduphole from the remainder of the regional communication units 810, anenergy and/or parameter (intensity, strength, wavelength, amplitude,frequency, etc.) of the ground penetrating signal 822 may be able to bereduced. In other embodiments, a data interrogator such as unit 620 or740) may be used in addition to or in lieu of the surface unit 810, forexample to serve as a back-up in the event of operation difficultiesassociated with surface unit 820 and/or to provide or serve as a relaybetween surface unit 820 and one or more units downhole such as aregional communication assembly unit 810 located at an upper end of astring of interrogator units.

For sake of clarity, it should be understood that like components asdescribed in any of FIGS. 5-7 may be combined and/or substituted toyield additional embodiments and the functionality of such components insuch additional embodiments will be apparent based upon the descriptionof FIGS. 5-7 and the various components therein. For example, in variousembodiments disclosed herein (including but not limited to theembodiments of FIGS. 5-7), the local, regional, and/or primary/masterdata interrogation/communication assembly units (e.g., units 310, 510,610, 620, 710, 740, and/or 810) may communicate with one another and/orequipment located at the surface via signals passed using a commonstructural support as the transmission medium (e.g., casing, tubular,production tubing, drill string, etc.), for example by encoding a signalusing telemetry technology such as an electrical/mechanical transducer.In various embodiments disclosed herein (including but not limited tothe embodiments of FIGS. 5-7), the local, regional, and/orprimary/master data interrogation/communication assembly units (e.g.,units 310, 510, 610, 620, 710, 740, and/or 810) may communicate with oneanother and/or equipment located at the surface via signals passed usinga network formed by the MEMS sensors (e.g., a daisy-chain network)distributed along the wellbore, for example in the annular space 26(e.g., in a cement) and/or in a wellbore servicing fluid inside casing20. In various embodiments disclosed herein (including but not limitedto the embodiments of FIGS. 5-7), the local, regional, and/orprimary/master data interrogation/communication assembly units (e.g.,units 310, 510, 610, 620, 710, 740, and/or 810) may communicate with oneanother and/or equipment located at the surface via signals passed usinga ground penetrating signal produced at the surface, for example beingpowered up by such a ground-penetrating signal and transmitting a returnsignal back to the surface via a reflected signal and/or a daisy-chainnetwork of MEMS sensors and/or wired communications and/or telemetrytransmitted along a mechanical conveyance/medium. In some embodiments,one or more of), the local, regional, and/or primary/master datainterrogation/communication assembly units (e.g., units 310, 510, 610,620, 710, 740, and/or 810) may serve as a relay or broker ofsignals/messages containing information/data across a network formed bythe units and/or MEMS sensors.

Referring to FIG. 8, a method 900 of servicing a wellbore is described.At block 910, a plurality of MEMS sensors is placed in a wellboreservicing fluid. At block 920, the wellbore servicing fluid is placed ina wellbore. At block 930, data is obtained from the MEMS sensors, usinga plurality of data interrogation units spaced along a length of thewellbore. At block 940, the data obtained from the MEMS sensors isprocessed.

In some embodiments, a conduit (e.g., casing 20 or other tubular such asa production tubing, drill string, workstring, or other mechanicalconveyance, etc.) in the wellbore 18 may be used as a data transmissionmedium, or at least as a housing for a data transmission medium, fortransmitting MEMS sensor data from the MEMS sensors 52 and/orinterrogation/communication assembly units situated in the wellbore 18to an exterior of the wellbore (e.g., earth's surface 16). Again, it isto be understood that in various embodiments referencing the casing,other physical supports may be used as a data transmission medium suchas a workstring, toolstring, production string, tubular, coiled tubing,wireline, jointed pipe, or any other physical structure or conveyanceextending downhole from the surface.

Referring to FIG. 9, a schematic cross-sectional view of an embodimentof the casing 1120 is illustrated. The casing 1120 may comprise agroove, cavity, or hollow 1122, which runs longitudinally along an outersurface 1124 of the casing, along at least a portion of a length of the1120 casing. The groove 1122 may be open or may be enclosed, for examplewith an exterior cover applied over the groove and attached to thecasing (e.g., welded) or may be enclosed as an integral portion of thecasing body/structure (e.g., a bore running the length of each casingsegment). In an embodiment, at least one cable 1130 may be embedded orhoused in the groove 1122 and run longitudinally along a length of thegroove 1122. The cable 1130 may be insulated (e.g., electricallyinsulated) from the casing 1120 by insulation 1132. The cable 1130 maybe a wire, fiber optic, or other physical medium capable of transmittingsignals.

In an embodiment, a plurality of cables 1130 may be situated in groove1122, for example, one or more insulated electrical lines configured topower pieces of equipment situated in the wellbore 18 and/or one or moredata lines configured to carry data signals between downhole devices andan exterior of the wellbore 18. In various embodiments, the cable 1130may be any suitable electrical, signal, and/or data communication line,and is not limited to metallic conductors such as copper wires but alsoincludes fiber optical cables and the like.

FIG. 10 illustrates an embodiment of a wellbore parameter sensing system1100, comprising the wellbore 18 inside which a wellbore servicing fluidloaded with MEMS sensors 52 is situated; the casing 1120 having a groove1122; a plurality of data interrogation/communication assembly units1140 situated on the casing 1120 and spaced along a length of the casing1120; a processing unit 1150 situated at an exterior of the wellbore 18;and a power supply 1160 situated at the exterior of the wellbore 18.

In embodiments, the data interrogation/communication assembly units 1140may be situated on or in casing collars that couple casing jointstogether. In addition or alternatively, the datainterrogation/communication assembly units 1140 may be situated in aninterior of the casing 1120, on an exterior of the casing 1120, or both.In an embodiment, the data interrogation/communication assembly units1140 a may be connected to the cable(s) and/or data line(s) 1130 viathrough-holes 1134 in the insulation 1132 and/or the casing (e.g., outersurface 1124). The data interrogation/communication assembly units 1140a may be connected to the power supply 1160 via cables 1130, as well asto the processor 1150 via data line(s) 1133. The datainterrogation/communication assembly units 1140 a commonly connected toone or more cables 1130 and/or data lines 1133 may function (e.g.,collect and communication MEMS sensor data) in accordance with any ofthe embodiments disclosed herein having wiredconnections/communications, including but not limited to FIG. 6.Furthermore, the wellbore parameter sensing system 1100 may furthercomprise one or more data interrogation/communication assembly units1140 b in wireless communication and may function (e.g., collect andcommunication MEMS sensor data) in accordance with any of theembodiments disclosed herein having wireless connections/communications,including but not limited to FIGS. 5-7.

By way of non-limiting example, the MEMS sensors 52 present in awellbore servicing fluid situated in an interior of the casing 1120and/or in the annulus 26 measure at least one wellbore parameter. Thedata interrogation/communication assembly units 1140 in a vicinity ofthe MEMS sensors 52 interrogate the sensors 52 at regular intervals andreceive data from the sensors 52 regarding the at least one wellboreparameter. The data interrogation/communication assembly units 1140 thentransmit the sensor data to the processor 1150, which processes thesensor data.

In an embodiment, the MEMS sensors 52 may be passive tags, i.e., may bepowered, for example, by bursts of electromagnetic radiation fromsensors of the regional data interrogation/communication assembly units1140. In a further embodiment, the MEMS sensors 52 may be active tags,i.e., powered by a battery or batteries situated in or on the tags 52 orother downhole power source. In an embodiment, batteries of the MEMSsensors 52 may be inductively rechargeable by the regional datainterrogation/communication assembly units 1140.

In a further embodiment, the casing 1120 may be used as a conductor forpowering the data interrogation/communication assembly units 1140, or asa data line for transmitting MEMS sensor data from the datainterrogation/communication assembly units 1140 to the processor 1150.

As noted above regarding FIGS. 1 and 3-4, it can be advantageous todetermine the progress or possible completion of a sealing (or“cementing”) operation, which can be accomplished by taking measurementsalong the casing string of the location and progress of the “top ofcement” (TOC). It can also be advantageous to monitor the quality ofsealant as a barrier, which includes the adequacy of the distribution ofsealant throughout the annulus between the casing and the formation.FIG. 11 is a cross-sectional schematic view of an example communicationassembly 1400 as may be used to measure the sealant (or other wellservicing fluids) present within different azimuthal regions of theannulus. Communication assembly 1400 is discussed below with referenceto some elements depicted in FIG. 5-7.

The example communication assembly 1400 includes a plurality of ribs1402 that extend longitudinally along the assembly and in spacedrelation to one another around the periphery of the assembly. In manyexamples, ribs 1402 will be hollow and will house control circuitry orother electronics, for example, voltage-controlled oscillators, memory,analog RF circuitry, sensors, power systems, processors, and othercircuitry to enable communication with an external location, etc.

In one embodiment, the ribs 1402 will further include interrogationcircuitry suitable for generating signals to both interrogate RFID tags(which may include additional MEMS sensor components, as describedearlier herein) and to receive signals from those interrogated RFIDtags. Such signals will be communicated to one or more antennas 1404operatively coupled to each instance of such interrogation circuitry).An instance of interrogation circuitry with at least one antenna willform an “RFID sensor assembly” for sensing the presence of RFID tags,and any additional information obtained when the RFID tags areinterrogated (such as sensor data). In one embodiment, interrogationcircuitry within rib 1402, can interrogate the RFID tags by scanningthrough a range of possible tag frequencies.

According to an embodiment, the interrogation circuitry may include asensor configurable to control the area of sensitivity. Moreparticularly, the configurable sensor may have extended azimuthal orlongitudinal coverage. As seen in FIG. 12A, a single sensor 2010includes a single sensor coil. The pattern of sensitivity is shown asthe lobe pattern 2000. One may determine that the gain is distributed inan undesirable pattern since the pattern may, for example, extend adistance away from the sensor in the z-direction, but not cover muchdistance across the sensor in the x-y direction. Accordingly it has beendiscovered that the use of multiple sensor coils in a single sensor canredirect and tune the sensitivity of the sensor. In one embodiment,sensors 2110, as shown in FIG. 12B, represent a pattern of equalsensitivity to the single lobe of FIG. 12A, but the sensitivity patternis distributed in a more desirable wider pattern as shown by the lobes2100. Here, the plurality of sensor coils produce a set of lobes thatprovide a wider sensitivity pattern over the x-y surface of the sensorallowing a tag near any of the three sensor coils to cause thecharacteristic drop in transmitted power at the tags center frequency.

The sensor as described can have from two sensor coils to about twentysensor coils. According to one embodiment, the sensor has at two sensorcoils, for example, at least three sensor coils, for example, foursensor coils, for example, from two coils to five coils. The skilledartisan would recognize that the placement and number of sensor coilscan be adjusted to improve the efficiency of measurement and to shapethe field pattern, thus resulting in the desired tag sensitivity.Further, the skilled artisan would recognize that impedance matchingelements may be used to reduce noise and minimize signal reflection.

As the number of coils changes, it will apparent to the skilled artisanthat the order of the filter can be changed. Appropriate filters caninclude any number of components, for example, the filter can be athird, fourth, fifth or sixth order filter or can go as high as afifteenth or eighteenth order filter.

In one embodiment as represented by the circuit diagram of FIG. 13A,each sensor coil shown in FIG. 12B can be driven independently, allowingfor fine resolution of the tag location. In this embodiment, the sensorcoil is found at the L2 inductor, represented as 500. In anotherembodiment as represented by FIG. 13B, all of the sensors of FIG. 12Bcan be driven with a single circuit. Such a design may provide desirablecomponent count reduction or power reduction.

FIG. 13B, like FIG. 13A, uses a band pass filter topology, butrepresents a higher order. According to this embodiment, the sensorseach have a sensor coil as an inductor which results in a seventh ordertopology as seen if FIG. 13B. The sense coils are at L2, L4 and L6.

Other suitable filter topologies will be readily apparent to the skilledartisan and can include Cauer topologies, for example, a Chebyshevfilter or an elliptical filter, depending upon the application.According to one embodiment, the sensor can have a Butterworth filtertopology, which has the benefit of having a maximally flat response.Butterworth filters have a monotonically changing magnitude function,unlike other filter types that have non-monotonic ripple in the passbandand/or the stopband. For this topology, the relative values of L2, L4and L6 are 1.2470, 2.0000, and 1.2470, respectively.

The sensor as described can be used in the frequency range of from about300 MHz to about 750 MHz. Multi-coil sensors as described herein may beused in the RFID sensor assembly as described and can sense both the RFsignal and the MEMS directly.

The multiple coils 2110 are collectively or individually coupled to amatching circuit (not shown). The matching circuit can for example,include the additional electrical structures as shown in FIGS. 13A and13B. Other arrangements of resisters, capacitors, inductors etc. arecontemplated within the instant disclosure.

The interrogation circuitry will be configured to determine a locationof the tag with respect to the antennas or by evaluating the amplitudeof a signal reflected from the tag and/or triangulation throughinterrogation of a tag by multiple RFID sensor assemblies. In many ofthese example implementations it will be preferable that the RFID tagseach have a unique tag ID, enabling the tag to be individuallydistinguished. In such systems, interrogation circuitry within rib 1402can be configured detect azimuthal direction of a tag based on atransmission pattern or amplitude of a reflected signal between a tagand one or more antennas 1404. Therefore, the nature or type of fluid inwhich tags are disposed can again be detected at different azimuthaldirections relative to communication assembly 1400 and casing 20.

As another example, tags may be interrogated though an RFID sensorassembly using a single antenna to both send interrogation signals toRFID tags and receive response signals from such tags. In otherexamples, an RFID sensor assembly may be configured to use two antennas,one for transmitting the interrogation signals and the other forreceiving the response signals. Each RFID sensor assembly (as definedbelow), includes at least one antenna and the identified interrogationcircuitry; however, each RFID sensor assembly will not necessarilyinclude a discrete instance of the interrogation circuitry. For example,the interrogation circuitry can be configured to send/receive signalsthrough multiple antennas, or through multiple pairs of antennas(depending on the RFID sensor assembly configuration). As will beapparent to persons skilled in the art, this functionality can beachieved through multiple mechanisms, for example, such as time shiftingsignals communicated to each antenna, or pair of antennas. In otherwords, in some examples, multiple RFID sensor assemblies may share asingle physical instance of interrogation circuitry.

Accordingly, each antenna (in a single antenna send/receive assembly),or each pair of antennas (in a dual antenna send-receive assembly) usedto communicate with RFID tags will be referred to as a “RFID sensorassembly” herein, with the understanding that the antennas will beoperably coupled to a discrete or shared instance of interrogationcircuitry to form the complete RFID sensor assembly. As will be apparentto persons skilled in the art, the location and orientation of theantenna(s) will in substantial part control the area interrogated by theRFID sensor assembly. Therefore, the location of each single antenna orpair of antenna operated by the interrogation circuitry to interrogateRFID tags will be identified as the “location” of the RFID sensorassembly, notwithstanding that the associated interrogation circuitrymay be placed at a different physical location.

The various electronic circuits within each rib 1402 can be configuredto communicate as desired with circuitry in another rib 1402. Suchcommunications can occur through use of any suitable mechanism as willbe apparent to those skilled in the art, for example, through use of aserial peripheral interface (SPI), though embodiments are not limitedthereto.

Communication assembly 1400 can be configured to be associated with thecasing string by a variety of mechanisms. Each communication assemblyincludes a body member 1418 supporting other components and facilitatingassociation with the casing string. In some embodiments, communicationassembly 1400 will include a sleeve body member configured toconcentrically engage the outer diameter of a length of casing. In suchcases, the sleeve body member can be placed over a length of casingbefore it is incorporated into the casing string 20, and then secured inplace by an appropriate mechanism. As one example, the sleeve bodymember may be secured against the upset at the box end of the casingsection and then clamped in place. In other examples, communicationassembly 1400 can include a body member configured as a specializedsection of casing 20, which either includes ribs 1402 as depicted inFIG. 14, or provides recesses or other structures to house the describedcomponents, and configured to be threadably inserted into the casingstring 20. In yet another alternative, communication assembly 1400 canhave a supporting body member configured as a hinged clamshell (or a twopart assembly) that can be secured around a length of casing, withouteither having to be joined into the casing string or the casing havingto be inserted through the body member, as with the above alternativeexamples.

One consideration in the configuration of communication assembly 1400will be the structures used for communicating information from thecommunication assembly. In some examples where communication is throughwireless RF communication, the communication assembly may include eithera toroidal coil with a core extending circumferentially to the assembly(and casing), or a solenoid coil with windings extendingcircumferentially around the assembly (and casing string) to transmitthe communication signals. Such assemblies may be more difficult toimplement in either a clamshell or a multi-section form, relative tosolid body member configurations such as the above examples.

Referring again to FIG. 11, example communication assembly 1400 includesfour ribs 1402 generally equally spaced around assembly, and thereforeequally spaced relative to the circumference of casing 20. As will beapparent to persons skilled in the art having the benefit of thisdisclosure, either a greater or lesser number of ribs may be utilized asdesired for particular application. In the depicted schematicrepresentation, a pair of antennas is provided between each pair ofadjacent ribs 1402 to sense RFID tags contained within fluid passing bycommunication assembly 1400 in the well annulus. In the depictedexample, the RFID sensor assemblies are presumed to be of a dual antennaconfiguration, and thus each pair of antennas between ribs, 1404 A-B,1404 C-D, 1404 E-F and 1404 G-H, is intended to form a respective RFIDsensor assembly under the definition provided above. In other examples,each antenna may represent a separate RFID sensor assembly. Because ofthe dual antenna RFID sensor assembly configuration assumed incommunication assembly 1400, each RFID sensor assembly will interrogateRFID tags within a respective azimuthal quadrant of the annulussurrounding communication assembly 1400 in a well. Any number of ribs,or corresponding structures, may be provided as necessary to house thenecessary circuitry, and as desired to provide interrogation within adetermined azimuthal region surrounding communication assembly 1400. Itshould be clearly understood that azimuthal detection is not limited tospace between the ribs (or corresponding structures). In some examples,RFID sensor assemblies may be located to sense “across” each rib tomaximize azimuthal sensing of the annulus.

Each RFID sensor assembly will generally be configured to detect withina determined azimuthal region of the annulus. In some implementations,these azimuthal regions may all be distinguished from one another, whilein others the azimuthal regions may partially overlap with one another.Additionally, each communication assembly may provide multiplelongitudinally offset RFID sensor assemblies, providing redundantsensing within a given azimuthal region. Of course, in many contemplatedconfigurations, multiple communication assemblies longitudinallydisposed along the casing string will measure corresponding azimuthalregions as other communication assemblies, albeit at different depthswithin the borehole.

For the present example, communication assembly 1400 includes four RFIDsensor assemblies, as noted above. However, additional ribs may beprovided, and may be used to support additional antennas in desiredorientations; and/or additional RFID sensor assemblies might belongitudinally offset along communication assembly 1400 relative tothose depicted in FIG. 11. Additionally, as discussed below, eachcommunication assembly can include one or more sensors of types otherthan RFID sensors. Examples (as described later herein), includeacoustic sensors, temperature sensors, etc. In many (but not all)examples, these additional sensors will also be arranged to senseparameters in a selected azimuthal region of the annulus surrounding thecommunication assembly. In the case of some types of sensors, it may bedetermined that only a single measurement is need proximate a givendepth, and thus only a single additional sensor of a selected type maybe used, rather than multiple azimuthally sensitive sensors of thattype. As with the RFID sensor assemblies, in many embodiments of suchsystems, the circuitry associated with such additional sensors (forcontrol, receiving, and/or processing of data from the sensors), and insome cases, the entire sensor itself, will be housed within one or moreof ribs 1402.

Referring now to FIGS. 14-16, these figures each depict a side view of arespective example of a communication assembly 1420, 1430, 1440,respectively. Components comparable to those discussed relative to FIG.14 are numbered similarly in FIGS. 12-14. In the depicted examples, eachcommunication assembly 1420, 1430, 1440, includes a plurality ofantennas arranged to provide a plurality of RFID sensor assemblies,though only one side of each communication assembly is shown.Accordingly, it should be understood that the described structures wouldbe replicated at a plurality of azimuthally offset locations around eachcommunication assembly 1420, 1430, 1440. Each antenna 1404 can beconfigured as a loop, dipole, etc., as desired. For the presentexamples, the antennas 1404 are each depicted as a loop antenna, againin a dual antenna RFID sensor assembly configuration. Each antenna maybe oriented on the respective communication assembly 1420, 1430, 1440,as desired to orient the field of the antenna in a desired direction.

Depending upon the specific materials of construction of variousportions of a respective communication assembly, antennas may be securedproximate a metallic surface. In such cases, the antennas can be mountedon a dielectric material 1406 to prevent electrical shorts against suchmetallic surfaces of the communication assemblies. In many cases, thisdielectric material can be of any type generally known to personsskilled in the art for electrically isolating and protecting electricalcomponents within downhole tools. For example, a material such asProtech DRB™ or Protech CRB™, available from the Halliburton Company ofHouston, Tex. can be used as a suitable dielectric material 1406. Ingeneral, the dielectric material is one capable of providing a necessarydegree of mechanical protection for the covered components, whileproviding a high resistance to DC current, but a low electrical lossfactor to signals in the 10 MHz to 1 GHz range. The same dielectricmaterial 1406, or another suitable material, can be disposed overantennas 1404 to protect them from the harsh environment within aborehole, including risk of abrasion, chemically induced deterioration,etc.

As noted above, in the dual antenna configuration of the RFID sensorassemblies, one antenna 1404 of a pair will transmit RF signals tointerrogate RFID tags from one antenna and the other antenna 1404 of thepair will be used to receive signals generated from the RFID tags inresponse to the interrogation signal. A compatible RFID tag (not shownin FIG. 12) passing in the field between the pair of antennas 1404 willgenerate a change in the transmission pattern between antennas 1404 inresponse to the interrogation signal.

The multi-coil circuitry approach as described herein provides theability to manipulate and change the range and area of detection. Sowhile the interrogation range of the antennae might remain unchanged,the selection of certain multi-coil circuit arrangements can change thedetection zone within which a MEMS will be observed. For example,assuming that the sensing assembly observes MEMS in an elliptical area,the change to a multi-coil system could change the nature of theellipse, for example, from broad to narrow.

In the dual antenna RFID sensor assembly configuration as describedearlier, the antennas can be arranged such that they define a generallyknown region of investigation for the respective RFID sensor assembly.In the example of communication assembly 1420 of FIG. 12, antennas 1412and 1414 can be oriented to provide a region of investigation extendinggenerally between the adjacent ribs 1402. As a result, the RFID sensorassembly with antennas 1412 and 1414 will investigate approximately aquadrant of the annulus surrounding communication assembly 1420, up to amaximum depth of investigation as determined by the specificimplementation.

Monitoring the number of tags identified by that RFID sensor assemblyprovides an indication of the volume of fluid in which those RFID tagsare carried proximate the quadrant investigated by the RFID sensorassembly. In other configurations, such as single antenna RFID sensorassemblies, the location of the antenna, in combination with anexperimentally determined region of investigation, can again provide ameasure of fluid within azimuthal region of investigation of the RFIDsensor assembly. In these types of measurements, the primary concern isas to the number of tags within an identifiable region rather than theplacement of any individual tag. Such a system can be implemented withrelatively basic passive RFID tags that merely respond to aninterrogation rather than transmitting a tag ID or other information.

Many possible arrangements of antennas are contemplated, and thedescribed system is not limited to any particular configuration ofantennas. The number, arrangement and spacing of antennas can beadjusted based on, for example, power needs, performance requirements,or borehole conditions.

As noted above, the communication assemblies may include a coil thatextends in either a toroidal or solenoid form concentrically to thecasing to facilitate wireless communication of obtained data. An examplecoil 1408 is depicted in each of communication assemblies 1420, 1430,1440, 1450.

Referring now to FIG. 15, the figure depicts an alternativeconfiguration of the communication assembly 1430. Communication assembly1430 includes an RFID sensor assembly including one antenna 1432oriented along one rib 1402, with a paired antenna oriented at an anglesuch as by being placed generally in a plane tangential to body member1408 of the communication assembly (i.e., in this example extendinggenerally in parallel to a tangent of the underlying casing string). Inthis example, a second similarly arranged RFID sensor assembly having apair of antennas 1436, 1438 is included at a longitudinally offsetlocation along body member 1408.

FIG. 16A depicts an alternative configuration of a communicationassembly 1440 in which an antenna 1446 is placed in a generally centrallocation between two ribs 1402 to serve as either a transmit or receiveantenna relative to a pair of nearby antennas 1442, 1444. Antennas 1442,1444 may be mounted, for example, on the adjacent ribs 1402, andconfigured to perform the opposite transmit/receive function. Thus, thecentral antenna 1446 is shared by two RFID sensor assemblies each havingantenna 1442 or 1444 as the other antenna. In some implementations, thisconfiguration may serve to provide increased certainty of investigationacross an azimuthal region of the surrounding annulus.

FIG. 16B depicts an alternative configuration of a communicationassembly 1450 in which an antenna 1446 is placed in a generally centrallocation between two ribs 1402 to serve as either a transmit or receiveantenna relative to a pair of nearby antennas 1442, 1444. Antennas 1442,1444 are mounted, for example, on the end of ribs 1402, and configuredto perform the opposite transmit/receive function. Thus, the centralantenna 1446 is shared by two RFID sensor assemblies each having antenna1442 or 1444 as the other antenna.

As is apparent from the discussion above, in many example systems, aplurality of communication assemblies (or communication units) will bedisposed in longitudinally-spaced relation to each other along thecasing 20, at least over a region of interest relative to either thesealing operation or to other downhole conditions.

As previously described regarding at least FIG. 1, a location, inparticular a top location, of the sealant (i.e., generically referred toas “top of cement,” or “TOC”) can be determined by finding a location oncasing string 20 where below it, primarily only tags associated with thesealant are identified, while above the location, only tags associatedwith other fluids, for example spacer fluid or drilling mud, areidentified. It will be understood there may be some mixing due toirregularities in the formation sidewalls that will trap some of thetags and possibly their associated fluids from the spacer and mud pumpedthrough annulus 26. Therefore, some tags associated with one type offluid may become mixed with a different type of fluid than thatindicated by the tag type.

Each communication assembly will preferably include an azimuthalindicator, for example a compass, to determine the orientation of thecommunication assembly once it is disposed within the borehole. With aknown orientation of the communication assembly, the orientation of eachrib and/or RFID sensor assembly will be known and therefore the quadrantor other azimuthally offset region being investigated will similarly beknown. The depth of each casing assembly can be known, for examplethrough a record of the location of each communication assembly as it isassociated with the casing string 20 as the string is placed in thewellbore, providing a measure of depth as to the surface.

In different examples, TOC measurement can be done after the pumping ofthe sealant is completed or the measurement can be a dynamic measurementof the TOC while the sealant is moving up annulus 26. The othermeasurements described herein facilitate measurements not only of theTOC, but also of the distribution of the cement or other sealant aroundthe casing over the region of the casing string that includes associatedcommunication assemblies. Regions where a minimal number of tags of thetype entrained within the sealant are located indicate a region where,for some reason, sealant has been blocked from reaching the region, orhas reached the region in a relatively limited volume. Identifying boththe depth and orientation where this occurs facilitates remediationefforts

Each communication assembly 1400 can report information associated withthe sensed tags to a surface system, for example surface system 630,using communication methods described above regarding FIG. 5-7. In someexamples, this may be as basic as a number of tags sensed within a giventime interval, grouped or formatted in a manner to indicate theazimuthal orientation of the sensing. Sometimes, this will include asimilar number of tags of each of a plurality of frequencies sensedwithin the time interval, and grouped or formatted to indicate theazimuthal orientation. In other example systems, RFID tags may be usedwhich include tag IDs, facilitating identification of which individualtags have been sensed. As noted above, the information associated withthe sensed tags may include MEMS sensor data.

Determining whether sealant (or another fluid in the borehole) isobserved in a volume throughout the surrounding annulus consistent witha successful cementing (i.e. sealing can be achieved through use ofrelatively simple RFID tags. As discussed earlier, similar relativelysimple RFID tags responsive to a different frequency may be dispersedinto other fluids, so that the progress of multiple fluids in theannulus can be observed.

While these measurements with relatively simple RFID tags are extremelyuseful, it must be understood that similar techniques are applicable toperform more sophisticated measurements. As described earlier, moresophisticated RFID tags having associated MEMS sensors of various typesmay be placed within the well servicing fluids. These MEMS sensor tagsmay include sensors for detecting temperature or any of a variety offluid properties, etc. These additional properties can be important tofully evaluating the quality of the sealing operation, particularly overtime.

For example, monitoring temperature in the annulus can identify regionswhere the sealant is curing either improperly or inconsistently relativeto other areas in the annulus. The ability to identify azimuthal regionswhere the temperature is inconsistent either with other regions or withexpectations can be useful in identifying defects such as fluidincursions. Such temperature sensing MEMS RFID tags may in some cases beactive (having a contained power source) or may be passive and energizedby the interrogation signal.

Sensed fluid properties may also be of significant use in evaluating thesealing operation. For example, a change in pH in a region of theannulus may also indicate a fluid incursion potentially adverselyaffecting the sealing operation. As with other measurements, the abilityto identify an azimuthal orientation of the sensed parameter providesvaluable information facilitating further analysis and/or remediationwithin the well. Again, in various embodiments these tags may be eitheractive or passive.

Turning to FIG. 17, the figure depicts a block diagram of a downholeassembly 1600. Downhole assembly 1600 includes, in various embodiments,any or all of the features, structures, functionality, etc., ofcommunication assemblies and/or sensor assemblies as described above(e.g., communication and/or sensor assemblies described with respect toFIG. 11-14). In various examples the downhole assemblies will be batteryoperated. As a result, in the absence of provisions for recharging thebatteries, once activated, the downhole assemblies will have a finitebattery life. The length of this battery life will be influenced by anumber of factors, including the sensor assemblies employed; the start,frequency and duration of the sensing performed; and the nature andfrequency of communications from (and in some cases to), the downholeassembly, among many other factors. Additionally, some well operations,such as primary cementing of a well, may extend over multiple days, andthere may be a need to monitor the downhole conditions of the cementeven after the end of the active operations. In some cases, thedesirability of such monitoring can extend for multiple days or weeks,and even, to the extent possible, for months or years. Accordingly,management of battery life in the harsh downhole environment can beimportant.

As shown, downhole assembly 1600 is in contact with wellbore fluid 1608when the assembly is deployed in a wellbore. This wellbore fluid 1608may include any wellbore servicing fluid described above, such asdrilling mud, spacer fluid, cement or other sealant, etc. Downholeassembly 1600 therefore is configured to be operated while coupled to acasing string in a borehole, and may be mounted on, integrally formedwith, or otherwise coupled to an exterior of a portion of a casingstring.

Downhole assembly 1600 includes a processor 1602, a storage device 1604,a battery 1606, an RFID sensor assembly 1610, an additional sensorassembly 1620, and an operating mode module 1630 in the embodimentshown. Other structures not depicted in downhole assembly 1600 may alsobe present in various embodiments, such as power couplings, powertransformers/adapters, memories, communication lines, signal lines,and/or other data connections, antennas, receivers, and/or other I/Odevices, etc. Each of the described or depicted components of downholeassembly 1600 is coupled to other components of the assembly asnecessary to provide the described and inherent functionalities.

Processor 1602 is configured to execute instructions stored onmachine-readable storage device 1604. These instructions may cause thedownhole assembly, or portions thereof, to perform particular operationsas will be described below with reference to this and additionalfigures. Storage device 1604 may be any suitable storage device, forexample, such as a memory device, and may be electronic, magnetic,optical or other storage. Storage device 1604 may also includeprogrammable memory in one embodiment. In another embodiment,instructions in storage device 1604 may be integrated with processor1602 (e.g., in embodiments in which processor 1602 is anapplication-specific integrated circuit (ASIC)) in cache memory; or maybe integrated into other structures (e.g., RFID sensor assembly 1610,additional sensor assembly 1620, operating mode module 1630 and/ocommunication module 1640). Additional processors and/or storage devicesmay also be present in some embodiments, and may be used in conjunctionwith processor 1602 and/or storage device 1604. In some instances,storage device 1604 may therefore also store instructions operable foruse with RFID sensor assembly 1610, additional sensor assembly 1620,operating mode module 1630, and/or other portions of downhole assembly1600.

Battery 1606 is configured to supply power within downhole assembly1600, and may correspond to any descriptions of internal batteriesdiscussed above. Accordingly, battery 1606 will provide power to othercomponents within downhole assembly 1600 as necessary. In someembodiments, battery 1606 may be rechargeable from an external source(for example, e.g., through induction). One or more additional batteriesmay also be present in some cases. Note that more, generally duplicate,or additional structures not shown in FIG. 16 may be present in manysystems, as would occur to those skilled in the art having the benefitof this disclosure.

RFID sensor assembly 1610 is configured to interrogate RFID tags in anannulus surrounding a casing string in a borehole in the embodimentshown. As described herein RFID sensor assembly 1610 includes at leastone sensor having multiple sensor coils 2100, and may also include anyfeatures, structures, functionality, etc., described above with respectto RFID sensor assemblies, or interrogators, in other embodimentsdescribed herein.

As shown, RFID sensor assembly 1610 is configured to interrogate and/orreceive signals from passive RFID tags such as tag 1650, as well asactive RFID tags such as tag 1652. Each of Tags 1650 and 1652 mayoperate in accordance with the descriptions of active and passive tagsprovided earlier herein. In most embodiments, downhole assembly 1600will include a plurality of RFID sensor assemblies, as described abovein reference to FIGS. 11 and 13-15.

Additional sensor assembly 1620 is configured to detect information inaddition to that detected by RFID sensor assembly 1610. Accordingly,sensor assembly 1620 may include one or more sensors configured to senseany of a variety of parameters of wellbore fluid 1608. In some examples,sensing of temperature in the wellbore fluids will be significant, andadditional sensor assembly 1620 will include a temperature module 1622configured to detect a temperature of wellbore fluid 1608. Additionalsensor assembly 1620 may thus include one or more probes (as describedin in the preceding section), or other means of sensing the temperatureof wellbore fluid 1608. In one embodiment, additional sensor assembly1620 includes a conductivity module 1624 configured to detect theconductivity of wellbore fluid 1608 through use of a plurality ofelectrodes 1626. Such a conductivity module will typically provide oneor more electrical stimulus signals (which will commonly be AC signals,but which in some cases may be DC signals) into the wellbore fluid, andwill detect the signal(s) after the current has passed through thewellbore fluid 1608. In many such conductivity modules, the signal willbe sensed at a plurality of distances from the electrode (or otherstructure) injecting the electrical stimulus signal into the wellborefluid. In other embodiments, the additional sensor assembly 1620 willinclude a sensor for monitoring other properties of the wellbore fluid.As just one example, a pH sensing module configured to detect pH valuesmay be provided. In other examples, the additional sensor assembly mayinclude any one or more of: an accelerometer, a tilt sensor, a magneticsensor, a pressure sensor, an acoustic sensor and an ultrasonic sensor.

Downhole assembly 1600 also includes an operating mode module 1630 inthe embodiment shown. Operating mode module 1630 includes circuit logicand/or stored instructions that control operating modes for downholeassembly 1600, RFID sensor assembly 1610, additional sensor assembly1620, and/or communication module 1640. Thus, operating mode module 1630is operable to cause all or a portion of downhole assembly 1600 tooperate in specific operating modes, for example, by performing periodicsensing operations, detecting triggering events, etc.

Communication module 1640 is configured to facilitate communicationswith devices external of the downhole assembly. Such communications maybe through any of a number of mechanisms, including wirelesstransmission to the surface, which will typically include wirelesscommunication of signals to one or more other downhole assemblieslocated relatively uphole, such that the signals are ultimately relayedto a surface location. In another example systems, communication may bethrough other mechanisms, such as acoustic signaling, etc.

In some cases, sensed information may be communicated to anotherdownhole location, for example another downhole assembly, for furtherprocessing prior to communication to a surface location. In addition tothe sensors being operated in a plurality of operating modes,communication module 1640 can also be operated in a plurality of modes.For example, during the pumping of cement into the well, just as thereis a need for a relatively increased information regarding the placementof the RFID tags (and therefore of the cement containing the tags),there is also a need for that information to be known to the systemoperator more quickly than at other times. Accordingly, thecommunication module 1640 will also be in communication with operatingmode module 1630 so that the operating mode of communication assembly1640 can be changed. For example, different operating modes may providefor different intervals at which downhole assembly 1600 communicatessensed data. Multiple operating modes of the communication module arecontemplated, as may be specifically defined either in advance of aparticular operation, or as may be desirable in view of sensed progressduring a given operation.

The above discussion and FIG. 16 identify some components of downholeassembly 1600 as “modules.” As used here, such a “module” may beimplemented through a variety of structures. For example, a module mayinclude dedicated circuitry or logic that is permanently configured(e.g., within a special-purpose processor, application specificintegrated circuit (ASIC), or array) to perform certain operations.Alternatively, a module may also include programmable logic or circuitry(e.g., as encompassed within a general-purpose processor or otherprogrammable processor) that is temporarily configured by software orfirmware to perform certain operations. Accordingly, the term “module”should be understood to encompass a tangible entity, however configuredor constructed, to operate in a certain manner or to perform certainoperations described herein. Considering embodiments in which modules orcomponents are temporarily configured (e.g., programmed), each of themodules or components need not be configured or instantiated at any oneinstance in time. For example, where the modules or components include ageneral-purpose processor configured using software, the general-purposeprocessor may be configured as respective different modules at differenttimes. Software may accordingly configure the processor to constitute aparticular module at one instance of time and to constitute a differentmodule at a different instance of time.

The accompanying drawings that form a part hereof, show by way ofillustration, and not of limitation, specific embodiments in which thesubject matter may be practiced. The embodiments illustrated aredescribed in sufficient detail to enable those skilled in the art topractice the teachings disclosed herein. Other embodiments may beutilized and derived therefrom, such that structural and logicalsubstitutions and changes may be made without departing from the scopeof this disclosure. This Detailed Description, therefore, is not to betaken in a limiting sense, and the scope of various embodiments isdefined only by the appended claims, along with the full range ofequivalents to which such claims are entitled.

As used herein, “about” is meant to account for variations due toexperimental error. All numerical measurements are understood to bemodified by the word “about”, whether or not “about” is explicitlyrecited, unless specifically stated otherwise. Thus, for example, thestatement “a distance of 0.01 to 0.4,” is understood to mean “a distanceof from about 0.01 to about 0.04.”

Although specific embodiments have been illustrated and describedherein, it should be appreciated that any arrangement configured toachieve the same purpose may be substituted for the specific embodimentsshown. This disclosure is intended to cover any and all adaptations orvariations of various embodiments. Combinations of the aboveembodiments, and other embodiments not described herein, will beapparent to those of skill in the art upon reviewing the abovedescription.

1. A method of making measurements in a borehole, comprising: providinga communication assembly in the borehole, wherein the communicationassembly is configured to communicate with radio frequencyidentification device (RFID) tags in the borehole; wherein thecommunication assembly includes a sensor assembly comprising at leastone sensor having at least two sensor coils; pumping a fluid into theborehole, the fluid containing a plurality of RFID tags; andinterrogating the plurality of RFID tags with the communication assemblyto determine the presence or absence of RFID tags within the borehole.2. The method of claim 1, wherein the sensing assembly comprises asleast one bandpass filter from 3^(rd) to 18th order.
 3. The method ofclaim 1, wherein each sensor coils is driven independently by its owncircuit.
 4. The method of claim 1, wherein all sensors are driven by asingle circuit.
 5. The method of claim 1, wherein the sensor has atleast four sensor coils.
 6. The method of claim 1, further comprisingplacing a plurality of communication assembles in longitudinally spacedrelation along a casing string in the borehole.
 7. The method of claim2, wherein each RFID sensor assembly includes a pair of antennas, andwherein the method further comprises: transmitting an interrogationsignal to the RFID tags from a first antenna of the pair of antennas;and receiving a response signal from the RFID tags through the secondantenna of the pair of antennas.
 8. The method of claim 2, wherein eachRFID sensor assembly includes a single antenna, and wherein the methodfurther comprises: transmitting an interrogation signal to the RFID tagsfrom the antenna; and receiving a response signal from the RFID tagsthrough the antenna.
 9. The method of claim 1, wherein the fluidcomprises a sealant.
 10. A communication assembly for use in a boreholewith a borehole wall and a casing string, comprising: an assemblyassociated with an annulus formed between the borehole wall and thecasing string, the assembly comprising; an RFID sensing assemblyconfigured to communicate interrogation signals to an RFID tag withinthe annulus and to receive signals from the RFID tag, the RFID sensingassembly including: an antenna arranged around the circumference of thecommunication assembly and configured to communicate with the RFID tagin the annulus; and at least one sensor comprising at least two sensorcoils; a data storage device to receive information associated withsignals received from the RFID tag; and a power source configured tosupply electrical power to the electronic control circuitry and the datastorage device.
 11. The communication assembly of claim 10, wherein thesensing assembly comprises as least one seventh order bandpass filter.12. The communication assembly of claim 10, wherein each sensor coils isconfigured to be driven independently by its own circuit.
 13. Thecommunication assembly of claim 10, wherein all sensors are configuredto be driven by a single circuit.
 14. The communication assembly ofclaim 10, wherein the sensor comprises at least four sensor coils. 15.The communication assembly of claim 10, wherein each RFID sensingassembly comprises a single antenna for both transmitting and receiving.16. The communication assembly of claim 10, wherein each RFID sensingassembly comprises a first antenna configured to transmit aninterrogation signal to an RFID tag and a second antenna configured toreceive a signal from an RFID tag.
 17. (canceled)
 18. The communicationassembly of claim 10, wherein the assembly is formed as an integral unitconfigured to threadably couple into the casing string.
 19. (canceled)20. (canceled)
 21. The communication assembly of claim 10, wherein theassembly comprises: a body member; and a plurality of ribs extendinggenerally longitudinally along the body member; and wherein the RFIDsensor assembly further comprises electronic control circuitry housedwithin one or more of the ribs.
 22. (canceled)
 23. A system for use in aborehole, comprising: a casing string comprising first and secondcommunication assemblies supported by the casing string and disposed inlongitudinally spaced relation to one another along the casing string,RFID tags located in a fluid in an annulus surrounding the casing stringwhen the casing string is in place within the borehole, a control unitconfigured to receive data indicative of the information received fromthe first and second communication assemblies to provide informationabout the fluid in the annulus; and wherein each communication assemblyis configured to obtain information associated with RFID tags in anannulus surrounding the casing when the casing is in place within aborehole; and wherein each communication assembly comprises a sensorassembly comprising at least one sensor comprising at least two sensorcoils.
 24. The system of claim 23, wherein the sensor comprises at leastone seventh order bandpass filter. 25.-33. (canceled)